Characterization of Selected Petroleum Source Rocks and Reservoir Rocks of Bengal Basin (Bangladesh) Based on Geochemical, Petrographical and Petrophysical Methods

CHARACTERIZATION OF SELECTED PETROLEUM SOURCE ROCKS AND RESERVOIR ROCKS OF BENGAL BASIN (BANGLADESH) BASED ON GEOCHEMICAL, PETROGRAPHICAL AND PETROPHYSICAL METHODS

MD. FARHADUZZAMAN

THESIS SUBMITTED IN FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF DOCTOR OF PHILOSOPHY

DEPARTMENT OF GEOLOGY FACULTY OF SCIENCE UNIVERSITY OF MALAYA KUALA LUMPUR

2013

UNIVERSITI MALAYA ORIGINAL LITERARY WORK DECLARATION

Name of Candidate: Md. Farhaduzzaman (I.C/Passport No: AD7162597)

Registration/Matric No: SHC100036

Name of Degree: Doctor of Philosophy

Title of Project Paper/Research Report/Dissertation/Thesis (“this Work”):

CHARACTERIZATION OF SELECTED PETROLEUM SOURCE ROCKS AND RESERVOIR ROCKS OF BENGAL BASIN (BANGLADESH) BASED ON GEOCHEMICAL, PETROGRAPHICAL AND PETROPHYSICAL METHODS

Field of Study: Coal / Petroleum Geology 1) I do solemnly and sincerely declare that: 2) I am the sole author/writer of this Work; 3) This Work is original; 4) Any use of any work in which copyright exists is done by way of fair dealing and for permitted purposes and any excerpt or extract from, or reference to or reproduction of any copyright work has been disclosed expressly and sufficiently and the title of the Work and its authorship have been acknowledged in this Work; 5) I do not have any actual knowledge nor do I ought reasonably to know that the making of this work constitutes an infringement of any copyright work; 6) I hereby assign all and every rights in the copyright to this Work to the University of Malaya (“UM”), who henceforth shall be owner of the copyright in this Work and that any reproduction or use in any form or by any means whatsoever is prohibited without the written consent of UM having been first had and obtained; 7) I am fully aware that if in the course of making this Work I have infringed any copyright whether intentionally or otherwise, I may be subject to legal action or any other action as may be determined by UM.

Candidate’s Signature Date

Subscribed and solemnly declared before,

Witness’s Signature Date

Name: Dr. Wan Hasiah Binti Abdullah Designation: Professor and Supervisor ABSTRACT

Nine gas fields and two coal fields of Bengal Basin, Bangladesh are studied in the current research based on geochemical, petrographical and petrophysical methods. The Surma

Group of Bengal Basin is composed of the Bhuban and Boka Bil Formations. Both formations are composed of sandstones and shales interpreted to have been deposited in a deltaic to shallow-marine environment. This is the most important geological unit of the basin since the entire hydrocarbon accumulations so far discovered in Bangladesh is found within these sandstones. These two formations also contain shale intervals with important source rock potential. Together with coal and coaly samples, shales and sandstones of the

Surma Group are the key subjects of the present study. Around 151 core samples of shale, sandstone and coal were investigated for this project. Shale and sandstone cores were chosen from ten wells of respective nine gas fields. Five bore holes of the Barapukuria and

Dighipara Basins were selected for coal, carbargillite and mudstone sampling. All shale, coal and coaly samples are subjected to a Source Rock Analyzer (SRA). After SRA screening, different standard geochemical methods (e.g., PyGC, GC, GCMS, AAS, TG-

DTA, EA and proximate analysis) were employed for the current study. Many shale and coal and coaly samples are examined with UV-facilitated microscope for maceral and vitrinite reflectance analyses. Poor to fair quality source rock potential is estimated for the studied Bhuban and Boka Bil shales. The organic matter found in both formations is thermally immature to early mature for hydrocarbon generation. The organic matters of the analyzed shales are derived from land plants of terrestrial environmental settings with minor contribution from marine sources. The siliciclastic sandstone samples are studied using both petrographic microscope, SEM and XRD for reservoir quality and diagenetic control analysis. Very good to excellent reservoir quality is evaluated by the present study.

Together with petrography, petrophysical analysis is also carried out for one well

(Rashidpur 4) and four potential hydrocarbon bearing zones are identified.

The depositional environment and hydrocarbon generation potential is another focus of the present study, emphasizing the biomarker characteristics of Permian coals of the

Barapukuria and Dighipara half-graben basins. In this project, organic facies distributions within the Permian succession are investigated focusing on coals, carbargillites and mudstones in the half-graben basins. The studied bituminous B rank coal consists dominantly of inertinite macerals followed by vitrinite and liptinite. The various facies models used commonly indicate forest swamps with mixed oxic-anoxic conditions under terrestrial settings with periodic flooding. Organic facies characteristics suggest that the coals are dominantly terrestrial with minor contributions from marine sources. The carbargillites correspond to a mixture of terrestrial and marine sources, whereby the mudstones being terrestrial with no marine influences. Very good hydrocarbon generation potential is estimated for the analyzed coal and coaly samples, ranging from fair to excellent. The carbargillites possess good potential for both oil and gas and followed by coals (mainly gas with minor oil) and mudstones (predominantly gas). Along with %Ro and

Tmax, the presence of exsudatinite, fluorinite and solid bitumen suggests the analyzed coal and coaly samples have already expelled hydrocarbons.

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ABASTRAK (Bahasa Malaysia)

Kajian terhadap sembilan lapangan gas and dua lapangan arang batu telah dijalankan menggunakan kaedah-kaedah geokimia, petrografi and petrofizik. Kumpulan Surma yang terletak di Lembangan Bengal terdiri daripada Formasi Bhuban and Formasi Boka Bil.

Kedua-dua formasi ini terdiri daripada batu pasir dan batuan syal yang ditafsirkan telah dienapkan di persekitaran delta hingga ke laut cetek. Unit geologi ini adalah amat penting bagi lembangan ini berdasarkan jumlah himpunan hidrokarbon yang telah dijumpai. Kedua- dua formasi ini juga mengandungi beberapa ketebalan batuan syal yang amat penting berpotensi sebagai batuan punca bagi hidrokarbon tersebut. Kesemua sampel arang batu, sampel yang mengandungi arang batu, batuan syal dan batu pasir ini merupakan keutamaan bagi kajian ini. Lebih kurang 151 sampel teras bagi batuan syal, batu pasir dan arang batu telah diselidik bagi projek ini. Teras-teras bagi batuan syal dan batu pasir telah dipilih daripada sepuluh telaga daripada sembilan lapangan gas di kawasan tersebut. Lima lubang teras daripada Lembangan Barapukuria dan Lembangan Dighipara telah dipilih bagi persampelan arang batu, batuan berkarbon (carbargillites) dan batu lumpur. Kesemua sampel-sampel batuan syal, arang batu dan batuan yang mengandungi arang batu ini tertakluk kepada kaedah Analisis Batuan Sumber (SRA). Selepas analisis SRA dijalankan, beberapa kaedah geokimia standard seperti PyGC, GC, GCMS, AAS, TG-DTA, EA dan anggaran atau analisis mutlak dan sebagainya telah dijalankan bagi kajian ini. Beberapa sampel batuan syal dan arang batu telah diuji dengan mikroskop yang mempunyai UV untuk analisis maseral dan vitrinit reflectans. Keputusan ujian bagi syal Bhuban dan Boka

Bil ini menunjukkan kualiti potensi arang batu yang lemah kepada baik. Bahan organik yang dijumpai di dalam kedua-dua formasi menunjukkan yang ianya tidak matang hingga ke tahap awal kematangan bagi penjanaan hidrokarbon. Bahan-bahan organik daripada batuan syal ini terhasil daripada tumbuhan daratan daripada persekitaran daratan dengan hanya sedikit sumbangan daripada sumber lautan. Sampel-sampel batu pasir silisiklastik

iv dikaji menggunakan kaedah mikroskop petrografi, SEM dan XRD untuk menentukan kualiti takungan hidrokarbon dan kawalan diagenetik di mana hasil kajian menunjukkan kualiti takungan adalah sangat bagus hingga cemerlang. Bersama-sama dengan petrografi, analisis petrofizik juga dijalankan bagi telaga Rashidpur 4 dan empat zon lagi yang dikenalpasti mempunyai potensi menghasilkan hidrokarbon.

Persekitaran enapan dan potensi penjanaan hidrokarbon juga merupakan tumpuan bagi kajian ini dengan penekanan pada ciri-ciri biomarker bagi arang batu Permian bagi

Lembangan Barapukuria dan Lembangan separa-graben Dighipara. Di dalam projek ini, taburan fasies organik bagi batuan Permian telah diselidiki dengan keutamaan pada arang batu, batuan berkarbon (carbargillites) dan batu lumpur di kawasan lembangan separa- graben. Arang batu berbitumen kelas B yang telah dikaji mengandungi kebanyakannya adalah maseral inertinit diikuti oleh vitrinit dan liptinit. Kajian model fasies yang digunakan menunjukkan kebanyakannya adalah hutan paya bakau dengan campuran keadaan oksid-anoksid kawasan daratan dengan banjir berkala. Ciri-ciri fasies organik arang batu menunjukkan kebanyakannya adalah dari daratan dengan sedikit sumbangan daripada lautan. Batuan berkarbon (carbargillites) pula menunjukkan campuran punca daratan dan lautan manakala batu lumpur pula adalah daratan sahaja tanpa dipengaruhi lautan. Dianggarkan potensi penghasilan hidrokarbon bagi sampel arang batu adalah sangat baik manakala bagi sampel yang mengandungi arang batu adalah baik hingga cemerlang.

Batuan berkarbon (carbargillites) mempunyai potensi minyak dan gas, diikuti arang batu kebanyakannya adalah berpotensi untuk gas dan sedikit minyak, manakala batu lumpur pula kebanyakannya adalah berpotensi untuk gas. Bersama-sama dengan %Ro and Tmax, kehadiran beberapa maseral yang penting seperti liptinit menunjukkan bahawa sampel arang batu dan sampel yang mengandungi arang batu yang dianalisis ini telah mengeluarkan hidrokarbon.

ACKNOWLEDGEMENTS The motherly behavior of my supervisor Prof. Dr. Wan Hasiah Binti Abdullah has made me very easy to accomplish this research work very successfully. I pass the times here at UM like my own home at Bangladesh just because of the brotherly behavior of my co- supervisor Dr. Md. Aminul Islam. Because of their very friendly cooperation and guidance I have never felt the home sickness. I am really very lucky for being a research student of these two excellent academicians with unique personalities. Mr. Zamri Rashid, Mr. Abdul Rahman, Mrs. Maisarah, Mrs. Zaitun and Mrs. Zaleha have assisted a lot during the laboratory analysis. The cooperation from Mrs Zurina Marzuki, Physics Department, University of Malaya (Malaysia) and School of Geoscience, University of Tsukuba (Japan) is acknowledged for providing their supports on FESEM and SEM respectively. Prof. Dr. Michael J. Pearson, Aberdeen University, UK and Mr. Peter Abolin, PETRONAS, Malaysia have assisted in different arenas of the present work. The cooperation from Mr Joyanta Dutto (Chulalongkorn University) and Afzal Hossain (Geokinetics) is acknowledged for petrophysical analysis. Dr. Aqueel Ashraf helped to carry out the elemental analyses. Minerals and Geoscience Department Malaysia (JMG) has analyzed the coal samples for proximate analyses. Mrs. Norishah Hashim of UM Geology assisted for translating the English Abstract to Bahasa Malaysia. SRA and RE analyses have been carried out in the Weatherford Laboratories (USA) and Geotechnical Services (Australia) respectively. Special thank goes to Dr. Rahman and Dr. Zakia (Ireland) who have helped a lot for English editing with the thesis.

I am grateful to Prof. Dr. Md. Hussain Monsur, Chairman of Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) and Mrs. Monira Akhter Chowdhury, Director General of the Geological Survey of Bangladesh (GSB) for permitting the usage of the samples and data for this study. Mr. Mortuza Ahmad Faruque, Managing Director, Bangladesh Petroleum Exploration and Production Co. Ltd. deserves the cordial thanks for providing the necessary shale and sandstone samples and related reports for the present research. During the official and sampling procedures, the friendly cooperation from the Petrobangla personnel Mr. R. A. Khan Kayas, Mr. Mahfuzul Haque, Mr. Fazlul Karim, Mr. Faisal vi

Ahmed, Mr. Akhtaruzzaman and Mrs. Zebunnahar Moly is cordially acknowledged. The BAPEX personnel Mr. Ruhul Chowdhury, Mrs. Nahar Begum, Mr. Babul Akhtar, Mr. Mamun Rony and Mr. Mozammel Haque have cooperated greatly in the official and sampling systems. Dr. Nehel Uddin (GSB), Mr. Abdul Hannan (BCMCL), Mr. Zahangir Alam (BCMCL) and Mr. Kamal Uddin (BCMCL) have helped a lot during the coal core collection. Sylhet Gas Fields Limited (A Company of Petrobangla) deserves the appreciation for providing the official supports including the required leave for the present research. Especial thank goes to Mr. Tofazzal Hossain, Managing Director of SGFL and his colleagues. I always remember the cooperation and mental supports form Mr. Shamsul Islam, Mr. Mozammel Chowdhury, Mr. N. A. Haider, Mr. Abdul Qadir, Mr. Rawnakul Islam Opu, Mr. Akbar Ali Tula, Mr. Ekramul Haque, Mr. Helal Uddin, Mr. Abdur Rahman Rumi, Mr. Nazrul Islam, Mr. Nuruzzaman Khan, Group-09 members, other colleagues of SGFL and former colleagues of Asia Energy Corporation (Bangladesh) Pty Ltd. I am cordially acknowledging the cooperation and motivation provided by Prof. Dr. Khalil R. Chowdhury and his colleagues at Jahangirnagar University while carrying out this study. I recall the inspirations delivered by Mr. Frans Boss, Mr. Ben Jonsen, Mr. John Anderson and Mr. Tony Armstrong (former colleagues) from GHD Australia. The examiners Prof. Dr. James C. Hower (University of Kentucky, USA), Prof. Dr. M. P. Singh (Banaras Hindu University, India) and Prof. Dr. Mohammad Y. Bakr (University of Malaya) deserve the sincere gratitude for their fruitful suggestions while reviewing the thesis. The Bright Sparks Fellowship BSP-APP-1080-2012, IPPP grant PV100-2011A and UMRG grants RG121/10AFR and RG145/11AFR from the University of Malaya for financial support are acknowledged.

Mrs. Murshida Khanam Ratna (my wife) has always supported me in order to carry out this research. Without her great sacrifices, the present PhD project would not have accomplished successfully. I am also grateful to those known and unknown peoples who have helped me in any stage of this research. Finally I am thankful to Almighty Allah who has powered me to accomplish this research successfully. Md. Farhaduzzaman July 2013 vii

Dedicated to my family members and late father

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CONTENTS OF THESIS Page no. Abstract ii Abstrak (Bahasa Malaysia) iv Acknowledgements vi Dedication viii CHAPTER 1: INTRODUCTION 1 1.1 Background 1 1.2 Exploration History, Petroleum System and Study Design 5 1.3 Aims and Objectives 9 1.4 Limitations of the Study 10 1.5 Outline of the Thesis 10 CHAPTER 2: LITERATURE REVIEW AND STUDY AREAS 12 2.1 Previous Studies 12 2.1.1 Shale 12 2.1.2 Coal 13 2.1.3 Reservoir sandstone 15 2.2 Regional Geology and Tectonics 16 2.3 Study Areas and their Stratigraphic Frameworks 20 2.3.1 Structure and Stratigraphy of the Barapukuria Coal Basin 20 2.3.1.1 Basement Complex (Archaean) in Barapukuria 22 2.3.1.2 Gondwana Group (Permian) in Barapukuria 22 2.3.1.3 Dupi Tila Formation (Mio-Pliocene) in Barapukuria 26 2.3.1.4 Barind Clay (Pleistocene to Recent) in Barapukuria 28 2.3.2 Structure and Stratigraphy of the Dighipara Coal Basin 28 2.3.2.1 Basement Complex (Archaean) in Dighipara 31 2.3.2.2 Gondwana Group (Permian) in Dighipara 32 2.3.2.3 Dupi Tila Formation (Mio-Pliocene) in Dighipara 32 2.3.2.4 Barind Clay (Pleistocene to Recent) in Dighipara 33 2.3.3 Stratigraphy of the Deep Basin unit of the Bengal Basin 33 2.3.3.1 Jaintia Group (Paleocene-Eocene) 35 2.3.3.2 Barail Group (Oligocene) 35 2.3.3.3 Surma Group (Mio-Pliocene) 37 2.3.3.4 Tipam Group (Pliocene) 39 2.3.3.5 Madhupur Clay Formation (Plio-Pleistocene) 39 2.4 Coal Resources in the Bengal Basin, Bangladesh 41 2.5 Hydrocarbons in the Bengal Basin, Bangladesh 41 CHAPTER 3: MATERIALS AND METHODS 43 3.1 Fieldwork and sampling 43 3.2 Laboratory work 44 3.2.1 SRA and RE 46 3.2.2 EA 49 3.2.3 Bitumen extraction (EOM) 49 3.2.4 Liquid column chromatography 50 3.2.5 PyGC 51 3.2.6 GC and GCMS 53 3.2.7 AAS 55 3.2.8 Polished block preparation (shale/coal) for microscopic study 56 3.2.9 Petrographic study of shale, coal and other coaly samples 58 ix

Page no. 3.2.10 Themrogravimetry-differential thermal analysis (TG-DTA) 60 3.2.11 Thin section preparation for sandstone samples 61 3.2.12 Petrographic study of sandstone samples 64 3.2.13 XRD analysis 65 3.3 Software Used 67 3.3.1 ProSim 67 3.3.2 Didger 4 68 3.3.3 Excel for petrophysical analysis 68 3.3.4 EndNote, StyleWriter and Turnitin 73 CHAPTER 4: RESULTS AND DISCUSSION 74 4.1 Petroleum Source Rock- Shales 75 4.1.1 Source rock properties 75 4.1.2 Maceral characteristics and kerogen type 79 4.1.3 Soluble extract and biomarker distributions 88 4.1.3.1 GC: TIC 89 4.1.3.2 GCMS: m/z 191 92 4.1.3.3 GCMS: m/z 217 97 4.1.4 Discussion 98 4.1.4.1 Thermal maturity 98 4.1.4.2 Hydrocarbon generation potential 100 4.1.4.3 Environment of deposition 103 4.1.4.4 Stratigraphic correlation 108 4.2 Petroleum Source Rock- Permian Coals 110 4.2.1 Macroscopic study of coals 111 4.2.1.1 Seam characteristics 111 4.2.1.2 Proximate analysis 112 4.2.1.3 Discussion 114 4.2.1.3.1 Moisture content 116 4.2.1.3.2 Volatile matters 117 4.2.1.3.3 Ash yield 117 4.2.1.3.4 Fixed carbon 117 4.2.1.3.5 Elemental concentrations 118 4.2.2 Microscopic study of coals 122 4.2.2.1 Macerals 122 4.2.2.1.1 Vitrinite group 122 4.2.2.1.2 Liptinite group 127 4.2.2.1.3 Inertinite group 135 4.2.2.1.4 Mineral matters 137 4.2.2.2 Microlithotypes 137 4.2.2.3 Discussion 141 4.2.2.3.1 Facies models 141 4.2.2.3.1.1 Mukhopadhyay (1986) facies model 142 4.2.2.3.1.2 Singh and Singh (1996) facies model 142 4.2.2.3.1.3 Diessel (1986) facies model 142 4.2.2.3.1.4 Calder et al. (1991) facies model 143 4.2.2.3.1.5 Hacquebard and Donaldson (1969) model 145 4.2.2.3.2 Depositional environment of the Barapukuria and 148 Dighipara Basin coals x

Page no. 4.2.3 Organic geochemical study of coals and associated 154 sediments 4.2.3.1 Source rock properties 154 4.2.3.2 Macerals and kerogen type 157 4.2.3.3 Soluble extract and biomarker distributions 161 4.2.3.3.1 GC: TIC 164 4.2.3.3.2 GCMS: m/z 191 168 4.2.3.3.3 GCMS: m/z 217 169 4.2.3.4 Discussion 170 4.2.3.4.1 Thermal maturity of organic matter 170 4.2.3.4.2 Organic facies characteristics 172 4.2.3.4.3 Hydrocarbon generation and expulsion 176 4.3 Petroleum Reservoir Rock- Sandstones 184 4.3.1 Petrography and diagenesis of sandstones 185 4.3.1.1 Sandstone texture and sorting 185 4.3.1.2 Sandstone composition 185 4.3.1.3 Sandstone classification 193 4.3.1.4 Diagenetic constituents 196 4.3.1.4.1 Quartz cements 196 4.3.1.4.2 Clay mineral authigenesis 197 4.3.1.4.3 Carbonate cements 200 4.3.1.4.4 Feldspar authigenesis 200 4.3.1.4.5 Dissolution and replacement 204 4.3.1.5 Compaction and grain packing 204 4.3.1.6 Discussion and reservoir implications 205 4.3.1.6.1 Implications to reservoir porosity and permeability 210 4.3.2 Petrophysical study of the well Rashidpur 4 213 4.3.2.1 Data analysis and interpretation 213 4.3.2.2 Identification of HC bearing zones 214 4.3.2.3 Shale distribution 215 4.3.2.4 Porosity distribution 216 4.3.2.5 Water saturation distribution 216 4.3.2.6 HC saturation distribution 226 4.3.2.7 Permeability distribution 226 4.3.2.8 HC moveability index 227 4.3.2.9 Bulk volume of water 227 4.3.2.10 Discussion 227 CHAPTER 5: CONCLUSIONS AND RECOMMENDATION 231

List of Figures xii List of Tables xvii List of Symbols and Abbreviations xviii List of Appendices xix Bibliography 271

LIST OF FIGURES Page no. Fig.1.1. Location map shows the studied nine gas fields and two coal basins (Imam, 2005). 3 Fig.1.2. The essential petroleum system elements of any sedimentary basin (AAPG, 2011). 7 Fig.1.3. Flow chart of the research approach and outlines of the current project. 8 Fig.2.1. Location map of study areas including Barapukuria and Dighipara Coal Basins and nine 18 gas fields. It shows the major tectonic elements of the Bengal Basin (modified after Khan, 1991; Reimann, 1993; Alam, et al., 2003; Shamsuddin et al., 2004; Imam, 2005). Fig.2.2. The positions of Gondwana basins in the vicinity of the Barapukuria and Dighipara 22 Coal Basins (after Uddin and Islam, 1992; Imam, 2005; Islam and Hayashi, 2008; Farhaduzzaman et al., 2012a). Fig.2.3. (a) Sampling locations shown in the study area of the Barapukuria Basin, Bangladesh. 23 Two cross-sections have also been added- (b) west to east, and (c) north to south (Imam, 2005; Islam and Hayashi, 2008; Farhaduzzaman et al., 2013c and 2013d). The analyzed samples are collected from Seam VI, Seam V and Seam IV. Fig.2.4. Generalized lithostratigraphic succession of the Barapukuria Basin, Bangladesh. (a) 27 represents the central north-western part of the basin, and (b) represents the central south- eastern part of the basin (Fig.2.3 for its location). The sampling locations are also shown. Fig.2.5. Sampling locations in the study area of the Dighipara Coal Basin, Bangladesh. 29 Fig.2.6. Generalized lithostratigraphic columns of two investigated bore holes GDH60 and 31 GDH62 of Dighipara Basin. Sampling positions are shown here (Farhaduzzaman et al., 2012a). Fig.2.7. Correlation of the studied ten wells (from north to south) of respective nine gas fields, 36 the Bengal Basin, Bangladesh. All of the analyzed samples are collected from Boka Bil and Bhuban Formations lying at the bottom part (Moinul et al, 1977; Nazim et al., 1982; Khan, 1991; Alam et al., 2003; Imam, 2005; Farhaduzzaman et al., 2012b and 2013b). Fig.2.8. Geological cross-section through the Platform (Province 1) unit and southern part of the 38 Deep Basin (Province 2) unit of the Bengal Basin. The location of cross-section line has been shown in Fig.2.1 (after Alam et al., 2003). Fig.2.9. The petroleum systems of the Bengal Basin, Bangladesh. The estimated hydrocarbon 40 resource is added (modified after Jamaluddin et al., 2001; Shamsuddin et al., 2004). 82 shale (SH), 33 sandstone (ST) and 36 coaly (CL) sampling numbers are also shown. Fig.3.1.1. (A) Shale and sandstone core samples stored in core-box of BAPEX; (B) and (C) 45 Shale core samples; (D) Sandstone core samples; (E) Coal core samples of the Dighipara Basin; (F) Coal core samples with organic-rich mudstone (top left at F) sample of the Barapukuria Basin. Fig.3.2.1. A Weatherford Source Rock Analyzer (SRA:TPH/TOC) installed at the petroleum 47 geochemistry laboratory of the Geology Department, University of Malaya. Fig.3.2.2. A Perkin Elmer 2400 elemental analyzer (CHNS/O) operated at the Chemistry 48 Department of the University of Malaya. Fig.3.2.3. Bitumen (EOM) extraction in progress; the sample is placed in a thimble. 50 Fig.3.2.4. Long column chromatography in progress for separating aliphatic (SAT) fraction. 51 Petroleum ether solvent, silica gel, alumina and slurry are also shown at table. Fig.3.2.5. An Agilent 6890N Series gas chromatograph (GC) and gas chromatography mass 52 spectrometer (GCMS). The Frontier Laboratories PY-2020iD model pyrolysis gas chromatograph (PyGC) unit shown here is also installed at the Geology Department, University of Malaya as an attachment Fig.3.2.6. The analytikjena contrAA®700 High Resolution Continuum Source Atomic 54 Absorption Spectrometer (HR-CS AAS) installation at the Department of Geology of the University of Malaya. Fig.3.2.7. Polishing in progress with Buehler Beta Grinder-Polisher automatic polishing 58 machine (A) and the polished coal/shale blocks (B). Fig.3.2.8. A LEICA DM6000M microscope and LEICA CTR6000 photometry system equipped 59 with fluorescence illuminators used at the Geology Department of the University of Malaya. Fig.3.2.9. A PerkinElmer Diamond TG-DTA installed at the Geology Department of the 62 University of Malaya (A); A typical TGA profile whereby the moisture content, volatile matter and fixed carbon of the analyzed coal sample are represented by the first, second and third weight loss steps respectively; The remaining weight at 950 ºC in oxygen corresponds to the ash content in % (B).

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Page no. Fig.3.2.10. Thin section preparation in progress operated at the Geology Department, University 63 of Malaya. Fig.3.2.11. A Leica DMLP optical microscopes installed at the Geology Department of the 64 University of Malaya; The PixeLINK digital cameras are attached for capturing images. Fig.3.2.12. A JEOL JSM-7600F field emission scanning electron microscope (FESEM) 66 operated at the Physics Department of the University of Malaya. Fig.3.2.13. A PANalytical X-ray Diffraction (XRD) machine working at the Geology 67 Department of the University of Malaya. Fig.4.1.1 Cross-plot of total organic carbon (TOC in wt.%) and remaining hydrocarbon 78 potential (S2 in mg HC/g rock) of the studied samples. Bhuban formation shows poor to fair quality source potential while Boka Bil shows mostly poor quality (adopted by Peters and Cassa, 1994; Dembicki, 2009). Fig.4.1.2. Distribution of vitrinite reflectance (%Ro ) and Tmax (°C) plotting with hydrogen 80 index (HI) of the analyzed samples. Bhuban formation depicts Type III/II (gas-oil prone) kerogen whereas Boka Bil is of Type III. Both formations are within immature to early mature oil window (see Appendices B1 and B3 for definitions) (modified from Peters and Cassa, 1994; Koeverden et al., 2011; cited by Farhaduzzaman et al., 2013a and 2013e). Fig.4.1.3. Photomicrographs showing macerals in shale samples under microscope. 83 Fig.4.1.4 Photomicrographs showing macerals in shale samples under microscope. 84 Fig.4.1.5 Photomicrographs showing macerals in shale samples under microscope. 85 Fig.4.1.6. PyGC pyrograms of Boka Bil and Bhuban shales (RP4SH1 and FN2SH9) display a 87 mixed kerogen of Types III and II. Fig.4.1.7. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 93 fraction of a studied Boka Bil sample (SB1SH29). It represents immature oil window (peak i.d. in Appendix B2). Fig.4.1.8. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 94 fraction of a studied Boka Bil sample (SB1SH48). It represents mature oil window (peak i.d. in Appendix B2). Fig.4.1.9. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 95 fraction of a studied Bhuban sample (KM1SH2). It represents immature oil window (peak i.d. in Appendix B2). Fig.4.1.10. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 96 aliphatic fraction of a studied Bhuban sample (T11SH68). It represents mature oil window (peak i.d. in Appendix B2). Fig.4.1.11. A cross-plot of Tmax (˚C) and production index (PI). Both of the studied Bhuban 102 and Boka Bil shale samples fall within and outside the hydrocarbon generation regime. But Bhuban shows relatively higher maturity (c.f., Powell, 1978). Fig.4.1.12. A cross-plot of HC yield and hydrocarbon in extract. The studied Bhuban and Boka 102 Bil shale samples correspond mostly to marginal-good quality petroleum source rock potential with marginal to early mature thermogenic condition (e.g., Powell, 1978). Fig.4.1.13. A triangular diagram from visual kerogen analysis (vol %). The analyzed Bhuban 103 and Boka Bil shales represent the generation potential for dry gas (gas-prone) (adopted after Tissot and Welte, 1978). Fig.4.1.14. Relationship between sterane compositions, source input and depositional 104 environment. Both of the analyzed Bhuban and Boka Bil Formation shales are dominated by terrestrial organic matter input. A minor contribution is from marine sources (e.g., Waples and Machihara, 1991). Fig.4.1.15. A plot of pristane/nC17 versus Phytane/nC18 for the examined samples infer oxicity 105 and organic matter the source rock depositional environment (e.g., Peters et al., 2005; Koeverden et al., 2011). The analyzed Bhuban and Boka Bil samples support the terrigenous Type III and mixed Type III/II source regions under oxic-anoxic condition. Fig.4.1.16. A cross-plot of Pr/Ph ratios and sterane C27/(C27+C29) values related to deposition 106 environment and source. Both of the analyzed Bhuban and Boka Bil shales suit terrestrial (oxic- anoxic) depositional setting and minor influence from pelagic source (c.f., Waseda and Nishita, 1998; Sawada, 2006; Hossain et al., 2009).

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Page no. Fig.4.2.1.1. Photographs of coal samples collected from the Barapukuria and Dighipara basins. 112 (A) and (B) are the bulk samples of Barapukuria Basin whereby (C) and (D) are the core samples of Dighipara Basin. The samples show different bands of coal, e.g., dull band (db) and bright parting (bp) along with a joint (j) in photograph D. This is a characteristic feature of a bituminous coal. Fig.4.2.1.2. The elemental concentration of the analyzed coal samples from the Dighipara 116 Basin. Mostly all of the identified elements cross their Clarke values which point to the environmental hazards while combustion. Fig.4.2.1.3. Photomicrograph shows iron and sulfur bearing mineral pyrite which is of 121 syngenetic (spy, A) or epigenetic (epy, B) origin. It is associated with vitrinite macerals observed under microscope with normal reflected white light under oil immersion. Fig.4.2.2.1. A triangular diagram illustrating peat-forming depositional environments based on 141 maceral compositions. The studied samples represent forest swamp, mildly oxic to anoxic conditions, with good tissue preservation (adopted by Mukhopadhyay, 1986). Fig.4.2.2.2. Environmental depositional conditions of the coals based on the composition of the 143 macerals and mineral matter contents. The explored samples fall within an alternation of oxic- anoxic moor (c.f., Singh and Singh, 1996). Fig.4.2.2.3. A cross-plot of the Gelification Index (GI) and Tissue Preservation Index (TPI) 144 showing the depositional settings of the peat mires. The analyzed samples fall mostly within terrestrial dry forest swamp and piedmont plain (e.g., Diessel, 1986). Fig.4.2.2.4 A cross-plot of the Ground Water Index (GWI) and Vegetation Index (VI) showing 145 the palaeoenvironments of the coal mires. The studied samples also imply mostly bog forest environment and swamp forest (adopted by Calder et al., 1991). Fig.4.2.2.5. A double triangular diagram based on microlithotypes, illustrating the coal facies. 147 The examined samples indicate a facies range from reed moor to forest moor (adopted by Hacquebard and Donaldson, 1969; Cited by Singh and Shukla, 2004). Fig.4.2.2.6. Coal depositional environments based on the composition of microlithotypes (free 148 of mineral matter). The analyzed coal samples indicate deltaic-lacustrine-fluvial environments (e.g., Singh and Singh, 1996; Singh and Shukla, 2004; Smyth, 2009). Fig.4.2.2.7. A triangular diagram based on microlithotypes, illustrating the depositional 149 environments. The analyzed samples represent the upper delta plain (mostly) to lower delta plain deposits (adopted by Hunt, 1982). Fig.4.2.2.8. The variation of different maceral indices (TPI, GI, VI and GWI) with vertical 152 depth patterns at the Barapukuria (BA, BB, BC and BD) and Dighipara (DA, DB, DC and DD). TPI, GI and VI values increase with depth in both basins. However, the GWI value decreases with depth at Barapukuria but increases with depth at Dighipara. It indicates that a similar depositional condition prevailed at the time of deposition for both basins, while the groundwater level is fluctuating. Fig.4.2.2.9. Schematic block diagram represents the palaeodepositional environments of the 153 Permian Gondwana coal deposits of the Barapukuria and Dighipara Basins, NW Bangladesh (Farhaduzzaman et al., 2012a). Fig.4.2.3.1. Pictorial comparison of Tmax, HI and OI values found from two different methods 156 SRA and RE. It shows a good agreement one another (see Appendix E1). Fig.4.2.3.2. Organic facies distribution from HI versus Tmax plot. The analyzed coals are 159 dominated by Type III-II, carbargillites by Type II-III and mudstones by Type III organic matter. All the samples being early to mid-maturity thermal conditions (see Appendices B1 and B3 for definitions) (minor modification from Bjorøy et al., 1981; Davies and Nassichuk, 1988; Goodarzi et al., 1987; van Koeverden et al., 2011). Fig.4.2.3.3. PyGC pyrograms of the analyzed coal, carbargillite and mudstone samples 163 representing Type III/II (dominant Type III), Type II/III mixture and Type III kerogen respectively (c.f., Dembicki, 2009). 4.2.3.4. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 165 fraction of a studied coal sample (BPCL15) of the Barapukuria Basin (peak i.d. in Appendix B2).

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Page no. 4.2.3.5. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 166 fraction of a studied carbargillite sample (DPCR42) of the Dighipara Coal Basin (peak i.d. in Appendix B2). 4.2.3.6. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic 167 fraction of a studied mudstone sample (BPMT22) of the Barapukuria Coal Basin (peak i.d. in Appendix B2). Fig.4.2.3.7. Organic facies related triangular diagram based on C27, C28 and C29 regular 171 sterane epimers. The analyzed coal samples correspond to mainly terrestrial organic matter with minor contribution from marine source. The carbargillite samples indicate mixed terrestrial and marine influenced sources and mudstones to terrestrial organic source (e.g., Waples and Machihara, 1991). Fig.4.2.3.8. A cross-plot of pristane/nC17 versus phytane/nC18 for the currently explored coal, 172 carbargillite and mudstone samples. It represents the sub-oxic depositional conditions with dominantly terrestrial organic matter (c.f., Peters et al., 2005). Fig.4.2.3.9. Environmental depositional conditions of coals and carbargillites based on the 174 macerals and mineral matter contents (adopted by Singh and Singh, 1996). The analyzed coal samples fall within alternating oxic-anoxic swamp. The carbargillite samples fall within the wet swamp with intermittent and moderate to high flooding. Fig.4.2.3.10. A cross-plot of TOC versus S2 while all the analyzed samples fall within the range 182 of fair to excellent hydrocarbon generation potential. Mudstone indicates the lowest potential and followed by carbargillite and coals (adopted by Peters and Cassa, 1994; Dembicki, 2009; cited by Farhaduzzaman, 2012a). Fig.4.3.1.1 A tri-plot of the modal composition of the studied Surma Group sandstones of the 195 Bengal Basin, Bangladesh. The sandstones place within the sublithic arenite to subfeldspathic arenite class (adopted by Folk, 1980). Fig.4.3.1.2. XRD analysis of clay minerals identified in the analyzed reservoir sandstones and 201 interlayered shales. (A) Non-treated air-dried diffractogram of sandstone samples. (B) Glycol saturated diffractogram of sandstone samples. It shows relative high abundance of clay mineral chlorite compared to others. Both air-dried and glycol-treated diffractograms show the similar responses due to the absence of smectite swelling clay. (C) 550 °C heated diffractogram of sandstone sample and hence the kaolinite peak is disappeared remained a small peak for chlorite. (D) Non-treated air-dried diffractogram of the interlayered shale sample is also shown which indicates the similar clay responses compared to those found in sandstone sample (A and B). It suggests the similar genetic origin for the clay minerals found both in sandstones and shales (e.g., Moore and Reynolds, 1979). Fig.4.3.1.3. Paragenetic sequence of the important diagenetic events observed in the studied 210 Surma Group sandstone reservoirs, the Bengal Basin, Bangladesh. Fig.4.3.1.4. A cross-plot of porosity and depth observed in the Tertiary reservoir sandstones of 211 the Bengal Basin, Bangladesh. It shows the overall porosity decreases with depth. Fig.4.3.2.1. Composite log responses of the hydrocarbon bearing Zone 1 (1447-1522 m) 218 identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.2. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing 219 Zone 1 (1447-1522 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.3. Composite log responses of the hydrocarbon bearing Zone 2 (2337-2350 m) 220 identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.4. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing 221 Zone 2 (2337-2350 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.5. Composite log responses of the hydrocarbon bearing Zone 3 (2466-2483 m) 222 identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.6. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing 223 Zone 3 (2466-2483 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

Page no. Fig.4.3.2.7. Composite log responses of the hydrocarbon bearing Zone 4 (2668-2731 m) 224 identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh. Fig.4.3.2.8. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing 225 Zone 4 (2668-2731 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

Photomicrograph 4.2.2.1. Show macerals in coal samples under microscope. 129 Photomicrograph 4.2.2.2. Show macerals in coal samples under microscope. 130 Photomicrograph 4.2.2.3. Show macerals in coal samples under microscope. 131 Photomicrograph 4.2.2.4. Show macerals in coal samples under microscope. 132 Photomicrograph 4.2.2.5. Show macerals in coal samples under microscope. 133 Photomicrograph 4.2.2.6. Show macerals in coal samples under microscope. 138 Photomicrograph 4.2.2.7. Show maceral associations in coal samples under microscope. 139 Photomicrograph 4.2.2.8. Show maceral associations in coal samples under microscope. 140 Photomicrograph 4.2.3.1. Show macerals in coal, carbargillite and mudstones samples under 178 microscope. Photomicrograph 4.2.3.2. Show macerals in coal, carbargillite and mudstones samples under 180 microscope. Photomicrograph 4.2.3.3. Show macerals in coal, carbargillite and mudstones samples under 181 microscope. Photomicrograph 4.3.1.1. Show minerals, cements and pores in sandstones in thin sections 188 under microscope. Photomicrograph 4.3.1.2. Show minerals, cements and pores in sandstones in thin sections 194 under microscope. Photomicrograph 4.3.1.3. Show minerals, cements and pores in sandstones under SEM. 198 Photomicrograph 4.3.1.4. Show minerals, cements and pores in sandstones under SEM. 202 Photomicrograph 4.3.1.5. Show minerals, cements and pores in sandstones under SEM. 203

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LIST OF TABLES Page no. Table 2.1. Stratigraphic succession of Barapukuria Basin (modified after Armstrong, 1991; 21 Alam et al., 2003; Islam and Islam, 2005). Table 2.2. Stratigraphic succession of Dighipara Basin (modified after Hasan and Islam, 2003; 30 Alam et al., 2003). Table 2.3. Generalized stratigraphic succession of Deep Basin unit or Province 2 (including 34 study area) of Bengal Basin (modified after Alam et al., 2003; Imam, 2005). Table 4.1.1. Source Rock Analyzer (of Rock-Eval equivalent) parameters and vitrinite 76 reflectance data of the analyzed shale samples (refer to Appendix B1). Table 4.1.2. Comparison between SRA and RE results of the analyzed shale samples (refer to 79 Appendix B1). Table 4.1.3. Elemental analysis (CHNS) results of the studied samples. 81 Table 4.1.4. A summary of the maceral contents (mineral free basis) of the studied shale 82 samples from Bhuban and Boka Bil Formations, Bengal Basin, Bangladesh. Table 4.1.5. Solubale extract yield and alkane parameters of the studied shale samples, Bengal 88 Basin (refer to Appendix B1). Table 4.1.6. Hopane biomarker parameters (measured from m/z 191) of the analyzed shale 90 samples (refer to Appendix B2). Table 4.1.7. Sterane and diasterane biomarker parameters (measured from m/z 217) of the 91 analyzed shale samples (refer to Appendix B2). Table 4.2.1.1. The proximate analysis results (air dried, ad-basis) obtained from TG-DTA 113 (ASTM D5800-96) method (UM Geology Lab; denoted by TGA) and ASTM D2013-07 (Geoscience Malaysia Lab; denoted by JMG) of the studied coal samples. Sulfur content (%) and gross calorific value (GCV, kcal/kg) are also added. ‘Arms’ denotes the results taken after Armstrong (1991). Table 4.2.1.2. Ash yield (%, ad basis) and elemental concentration (ppm, ad basis) with Clarke 115 values or world average of Dighipara Basin coals. Table 4.2.2.1. A summary of maceral and mineral matter contents (vol. %) of the analyzed coal 123 samples (22 cores and 5 bulks) of Barapukuria and Dighipara Basins. GI - TPI and GWI -VI values are also shown. Table 4.2.2.2. A summary of maceral concentrations in mineral free basis (vol. %) of the 124 analyzed coal samples (22 cores and 5 bulks) of Barapukuria and Dighipara Basins. Table 4.2.2.3. A summary of concentrations of microlithotype and carbominerite (vol. %) of the 125 analyzed coal samples (22 cores and 5 bulks) of Barapukuria and Dighipara Basins. Table 4.2.2.4. A summary of concentrations of microlithotypes in mineral free basis (vol. %) of 126 the analyzed coal samples (22 cores and 5 bulks) of Barapukuria and Dighipara Basins. Table 4.2.3.1. Source Rock Analyzer (of Rock-Eval equivalent) parameters and vitrinite 155 reflectance data of the analyzed samples- coal, carbargillite and mudstone (refer to Appendix B1). Table 4.2.3.2. A summary of maceral and mineral matter (MM) contents (vol.%) of the 158 analyzed samples- coal, carbargillite and mudstone. Table 4.2.3.3. Soluble extract yield and alkane parameters of the studied coal, carbargillite and 162 mudstones (refer to Appendix B1). Table 4.2.3.4. Hopane biomarker parameters (measured from m/z 191) of the analyzed coal, 164 carbargillite and mudstones (refer to Appendix B2). Table 4.2.3.5. Sterane and diasterane biomarker parameters (measured from m/z 217) of the 169 analyzed coal, carbargillite and mudstone samples (refer to Appendix B2). Table 4.3.1.1. Petrographic results (%) of Surma Group reservoir sandstones of the Bengal 186 Basin, Bangladesh. Table 4.3.2.1. Permeable zones identified from the log based petrophysical analysis of the well 215 Rashidpur 4, the Bengal Basin, Bangladesh. Table 4.3.2.2. Log based petrophysical analysis results of 4 hydrocarbon (HC) bearing zones 217 identified in well Rashidpur 4 of Bengal Basin, Bangladesh.

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LIST OF SYMBOLS AND ABBREVIATIONS

AAS : Atomic absorption spectrometry ASTM : American Society for Testing and Materials BAPEX : Bangladesh Petroleum Exploration and Production Company Limited (A Company of Petrobangla) BCMCL : Barapukuria Coal Mining Company Limited (A Company of Petrobangla) BB : Boka Bil Formation BBS : Bangladesh Bureau of Statistics BG : Begumganj Gas Field Bh : Bhuban Formation BK : Bakhrabad Gas Field BP : Barapukuria Coal Basin BVW : Bulk volume water BWDB : Bangladesh Water Development Board CL : Coal CR : Carbargillite DP : Dighipara Coal Basin FESEM : Field emission scanning electron microscope Fm : Formation FN : Fenchuganj Gas Field GC/GCMS : Gas chromatography / Gas chromatography mass spectrometry GDH/DOB : Geological Drill Hole GIIP 2P : Gas Initially In Place Proven + Probable GRlog : Gamma ray reading from formation GRmax : Gamma ray reading from shale (gamma ray maximum) GRmin : Gamma ray reading from clean sand (gamma ray minimum) GSB : Geological Survey of Bangladesh HCU : Hydrocarbon Unit IGR : Gamma ray index K : Permeability of formation KM : Kamta Gas Field KT : Kailas Tila Gas/Oil Field m : Cementation exponent MMSCFD : Million Standard Cubic Feet per Day MT : Mudstone Φ : Porosity ΦN : Neutron porosity ΦD : Density porosity NPD : Norwegian Petroleum Directorate Petrobangla : Bangladesh Oil, Gas and Mineral Corporation (BOGMC) Ρb : Bulk density of formation Ρf : Density of the fluid in the borehole Ρh : Hydrocarbon density Ρma : Density of the formation matrix PT : Patharia Gas Field / Structure PyGC : Pyrolysis gas chromatography RE : Rock-Eval pyrolysis 6 RILD : Resistivity induction log deep RSFL : Resistivity of spherically focused log Rm : Resistivity of drilling mud Rmc : Resistivity of mudcake Rmf : Resistivity of mud filtrate Rt : Resistivity of uninvaded zone Rw : Resistivity of formation water Rxo : Resistivity of flushed zone RP : Rashidpur Gas Field SEM : Scanning Electron Microscope xviii

SB : Shahbazpur Gas Field SGFL : Sylhet Gas Fields Limited (A Company of Petrobangla) SH : Shale Sh : Hydrocarbon saturation (1 – Sw) SP : Spontaneous potential SSP : Static spontaneous potential SRA : Source Rock Analyzer ST : Sandstone STOIIP : Stock Tank Oil Initially In Place STOOIP : Stock Tank Original Oil In Place Swirr : Irreducible water saturation Sw : Water saturation Sxo : Water saturation of flushed zone T : Titas Gas Field TCF : Trillion Cubic Feet Tf : Formation temperature XRD : X-ray Diffraction UM : University of Malaya Vsh : Volume of shale

LIST OF APPENDICES Page no. Appendix A1. Published in International Journal of Coal Geology (ISI-cited; Q1; IF = 2.70). 239 Appendix A2. Published in Journal of Petroleum Geology (ISI-cited; Q2; IF = 1.01). 240 Appendix A3. Published in Journal of Asian Earth Sciences (ISI-cited; Q1; IF = 2.42). 241 Appendix A4. Published in Journal of Petroleum Geology (ISI-cited; Q2; IF = 1.01). 242 Appendix A5. Accepted in Journal of the Geological Society of India (ISI-cited; Q4; IF = 0.59). 243 Appendix A6. Under review in Geosciences Journal (ISI-cited; Q2; IF = 0.81). 244 Appendix A7. Under review in J. of the Geological Society of India (ISI-cited; Q4; IF = 0.59). 245 Appendix A8. Under review in Sains Malaysiana (ISI-cited; Q3; IF = 0.27). 246 Appendix A9. Under review in Malaysian Journal of Science (Scopus-cited). 247 Appendix B1: Some definitions and measurement terms used in the literature. 248 Appendix B2: Peak assignments for alkane HCs in the gas chromatograms of the aliphatic 249 fractions (i) in the m/z 191 mass fragmentogram and (ii) m/z 217 mass fragmentogram. Appendix B3: Some important standard parameters used for petroleum source rock screening in 250 the thesis. Appendix C1: TOC (wt.%) of both Boka Bil and Bhuban shales plotted with vertical depth 251 profile (m) of the study area. It shows TOC increases with overall depth increasing irrespective of any particular wells. Appendix C2: Modified van Krevelen diagram (HI versus OI) shows that the analyzed both 252 Bhuban and Boka Bil samples consist of a mixture of Type III and II kerogens. Appendix C3: PyGC pyrograms of Boka Bil and Bhuban shales (PT5SH14 and KM1SH4) 253 display a mixed kerogen of Types III and II. Appendix C4: Pictorial presentation of CPI values shows that the members of odd-numbered 254 and even-numbered n-alkanes alternately predominate each other in both of the analyzed Bhuban and Boka Bil samples. Appendix C5: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 255 aliphatic fraction of a studied Boka Bil sample (PT5SH10). It represents immature oil window (peak i.d. in Appendix B). Appendix C6: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 256 aliphatic fraction of a studied Boka Bil sample (BK9SH71). It represents mature oil window (peak i.d. in Appendix B). Appendix C7: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 257 aliphatic fraction of a studied Bhuban sample (FN2SH7). It represents immature oil window (peak i.d. in Appendix B).

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Page no. Appendix C8: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 258 aliphatic fraction of a studied Bhuban sample (BG1SH6). It represents mature oil window (peak i.d. in Appendix B). Appendix C9: Cross-plot of bc/C30-hopane and ol/C30-hopane (oleanane index) with respective 259 depth (samples) shows that bc/C30-hopane ratio decreases and ol/C30-hopane ratio increases with depth. It indicates the relative maturity increase with depth. Appendix C10: The identified similar organic geochemical and organic petrological properties 260 of the analyzed Bhuban and Boka Bil Formations, Bengal Basin, Bangladesh. Appendix D1: Bar diagram displaying the concentrations of macerals and minerals (vol. %) of 261 the studied Permian coals of Bangladesh. Appendix D2: Bar diagram displaying the concentrations of microlithotypes (maceral 262 associations) and carbominerites (vol. %) of the studied Permian coals of Bangladesh. Appendix E1: Comparison between SRA and RE results of the analyzed coal, carbargillite and 263 mudstone samples (refer to Appendix B1). Appendix E2: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 264 aliphatic fraction of a studied coal sample (DPCL35) of Dighipara Coal Basin (peak i.d. in Appendix B2). Appendix E3: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of 265 aliphatic fraction of a studied carbargillite sample (BPCR11) of Barapukuria Coal Basin (peak i.d. in Appendix B2). Appendix E4: Pictorial presentation of CPI values whereby all of the analyzed coal, carbargillite 266 and mudstone samples show the dominance of odd carbon numbered n-alkanes. It indicates the terrestrial dominated organic facies in the depositional system. Appendix F1: A sample report of a reference management software EndNote X5 that has been 267 used for the thesis. Appendix F2: A standard report of StyleWriter 4.0 software for checking English Language. It 268 shows the status of English used in the thesis is “Excellent”. Appendix F3: A sample report for checking the originality using Turnitin software. It reports 269 19% similarity index with the thesis whereas more than 5% comes from the publication of author himself based on present research. Appendix G: Contributors of the thesis. 270

CHAPTER 1: INTRODUCTION

1.1 Background

Bangladesh is a country covering an area of 147570 square kilometers. It lies between latitudes of 20°N-27°N and longitudes of 88°E-93°E and borders India and with a small part of Myanmar (Bangladesh Bureau of Statistics, 2011). The Bengal Basin is located at the northeast-southeast corner of the Indian subcontinent (Fig.1.1). Geographically two- thirds of the basin is covered by on- and offshore Bangladesh. The rest one-third lies within

India surrounding Bangladesh on three sides- east, west and north (Banerji, 1984). To the south, the basin extends to the Bay of Bengal. So far, twenty five (25) gas fields and only one minor oil field have been discovered in the Bengal Basin, Bangladesh. The Miocene

Surma Group has been found as a host for the discovered gas (28 trillion cubic feet) and oil

(137 million barrels) in Bangladesh (Shamsuddin et al., 2004; Hossain, 2012).

Northward migration of the Indian plate and convergence with Eurasian plate about 55 Ma resulted in developing the Bengal Basin in the west and the Burmese Basin in the east. The

Eastern Petroleum Province and the Western Petroleum Province are the main two petroleum systems in the Bengal Basin, Bangladesh. So far, the entire hydrocarbon discovery is demarcated in the Eastern Petroleum Province. The coal is found in the

Western Petroleum Province. Stratigraphy of the Eastern Petroleum Province (22km thick sediments) is different from that of the Western Petroleum Province (400m thick sediments). In general, the Basement Complex (at bottom), Gondwana Group, Dupi Tila

Formation and Barind Clay Formation are the major stratigraphic units in the Western

Province. On the other hand, the Eastern Petroleum Province includes Jaintia Group

(bottom unit), Barail Group, Surma Group, Tipam Group, Dupi Tila Formation and

Madhupur Clay Formation (Alam et al., 2003).

1 Natural gas is the most important energy resource in Bangladesh. Around 94.96% power generation is based on hydrocarbons (mostly gas with oil). The share of coal in power is only 2.41% (BPDB, 2012). The national industry, agriculture, business, investment, sustainable development and infrastructure are mostly dependent on the natural gas. Several workers have already carried out their researches on natural gas and petroleum systems.

However, the research is still inadequate compared to the huge coverage of the basin and increasing demand of natural gas. The national policy makers and the experts of

Bangladesh are looking forward to improve the gas and oil sector. Therefore, they are trying to encourage more research based on petroleum systems. Accordingly, there is initiative and effort to carry out more focused research on oil and gas and its related petroleum systems.

The Surma Group, up to 5 km thick, consists of the Bhuban and Boka Bil Formations. This is exposed in the Sylhet and Chittagong hills, Bangladesh. Both formations, consisting of sandstones and shales, are interpreted to have been deposited in a deltaic to shallow-marine environment (Holtrop and Keiser, 1970). All the hydrocarbons so far discovered in

Bangladesh have been found within the Bhuban and Boka Bil Formation sandstones. This is the most important geological unit of the basin. These formations also contain shale intervals showing important source rock potential (Imam, 2005). Overlying marine shale acts as a basin-wide seal.

Many authors have recently reported the organic geochemical and petrological evidences as diagnostic for characterizing extracts and oils gained from different organic matter and environment.

Fig.1.1. Location map shows the studied nine gas fields and two coal basins (Imam, 2005).

For example, Espitalie et al. (1977), Mukhopadhyay et al. (1991), Hunt (1991), Wan

Hasiah (1999a), Wan Hasiah and Abolins (1998), Farrimond et al. (1998), Petersen et al.

(2005), Banerjee et al. (2006) and Dutta et al. (2011) have worked on different topics of

3 petroleum source rock. Considering the Bengal Basin, none of the works, however, are based on detail organic geochemistry and petrography of the Surma Group shales of

Bangladesh. Now, it is worthwhile to carry out more research on Surma Group shales in the

Bengal Basin. The focus of the present work is on the hydrocarbon source potential and environmental conditions using organic matter quantity, quality and thermal maturity. The petrographic characteristics of the Surma Group shales covering almost whole eastern

Bengal Basin (nine gas fields), Bangladesh, have also been discussed.

In the current research, the reservoir quality and diagenetic controls of the Surma Group sandstones are carried out using petrographical methods, x-ray diffraction (XRD) and scanning electron microscopy (SEM). The well log based petrophysical evaluation of the reservoir sandstones is accomplished for assessing the reservoir properties. Although there are some publications on the reservoir sandstones, they are not enough. Therefore, the findings of the current analysis will supplement the present understanding of the related petroleum systems of the Bengal Basin, Bangladesh.

The geophysical surveys, including gravity and magnetic anomaly maps, identified five

Permian coal-bearing half-graben basins found in the western Platform area of the Bengal

Basin, northwest Bangladesh (Hasan and Islam, 2003). Later detail seismic and geological drilling with geophysical logging confirmed these coals (about 3 billion tons) including the

Barapukuria and Dighipara Basins. The Permian Gondwana succession consists of sandstones and mudstones with thick coal seams and carbargillites. Sandstone with cross- bedding was deposited in high-energy based fluvial environments.

4 The mudstone was deposited in low-energy delta plain whereby coal and carbargillites in calm and quiet (low-energy) swamp settings (Alam et al., 2003; Imam, 2005). Thus, the organic facies developed in these rock units are different. So far, no previous work on assessing organic petrology, organic geochemistry and hydrocarbon source potential has published for Bangladesh coals. Now, it is an urgent issue to carry out further research on coals. The depositional environment and hydrocarbon generation potential is the focus of the present study. It highlights the biomarker characteristics of the Permian coals of the

Barapukuria and Dighipara basins. No published papers included analyses of the coals and their relationship with other fine-grained sediments. In present study, organic facies distributions within the Permian succession are examined, concentrating on the coals, carbargillites and mudstones in the half-graben basins of Bangladesh. The term

‘carbargillite’ used here refers to clay-rich coals (20-60% of clay minerals by volume as defined by Mackowsky, 1982).

1.2 Exploration History, Petroleum System and Study Design

The term petroleum originates from Latin word ‘petroleum’ from Latin ‘petra’ means rock and Latin ‘oleum’ means oil. It is a naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. Petroleum, the fossil fuel, is found in geologic formations beneath the

Earth’s surface. It is formed when large quantities of dead organisms (e.g. zooplankton and phytoplankton) are buried underneath rock and undergo extensive heat and pressure (Tissot and Welte, 1984). It occurs as three phases including oil, gas and condensate. Oil is a liquid at surface temperature and pressure and it consists of compounds containing six or more carbon atoms. Natural gas exists as vapor phase at surface temperature and pressure and it consists of compounds containing five or fewer carbon atoms.

5 Condensate exists as gaseous phase in reservoir sediments underneath the Earth’s surface but it converts liquid phase when brought to the surface. Petroleum has a long history for its discovery, identification, technology and use. It is now important across the society, encompassing economics, politics and technology. The rise in importance is mostly because of the invention of the internal combustion engine, the rise in commercial aviation and the increasing use of plastic and pesticides. More than 4000 years ago, according to Herodotus and Diodorus Siculus, asphalt was used for constructing the walls and towers of Babylon. Ancient Persian tablets indicate the medicinal and lighting uses of petroleum in the upper levels of their society. By 347 AD, oil was produced from bamboo- drilled wells in China (Chisholm and Hugh, 1911). Edwin Drake’s 1859 well in

Pennsylvania is popularly considered the first modern well for which a steam engine was used for drilling. However, in mid-19th century, there was considerable activity before

Drake in various parts of the world. A hand-drilled well in the Baku region in 1848 has been documented. An early commercial well was hand dug in Poland in 1853 and another in nearby Romania in 1857. Romania was the first country in the world to have its crude oil output officially recorded in international statistics, namely 275 tones in 1857. Access to petroleum was and still is a major factor in several military conflicts of the twentieth century, including World War II, during which petroleum was a major strategic asset and were extensively bombed. Petroleum exploration in North America during the early 20th century later led to the U.S. becoming the leading producer by mid-century. Petroleum's worth as a portable, dense energy source powering most of vehicles and as the base of many industrial chemicals makes it one of the world's most important commodities. The top three petroleum producing countries are Saudi Arabia, Russia and the United States

(IEA, 2010).

Fig.1.2. The essential elements (source, reservoir, migration route, trap and seal) of a petroleum system of any sedimentary basin (AAPG, 2011).

The techniques used for petroleum exploration first involve the assessment of the petroleum systems of the associated sedimentary basin. The formation of hydrocarbons depends on the coexistence of all the petroleum essential elements (source rock, reservoir rock, seal rock, trap and migration route) and processes (generation, migration, accumulation, preservation and timing) whose origin is a single pod of active source rock in the sedimentary basin, known as petroleum system (Fig.1.2). Absence of any of these elements and processes results no hydrocarbon accumulation in the subsurface (Tissot and Welte,

1984; AAPG, 2011). ‘Source rock’ and ‘reservoir rock’, the two essential petroleum system elements of the Bengal Basin, Bangladesh, are the focus of the current project.

Fig.1.3. Flow chart of the research approach and outlines of the current project.

After project finalization, the research design is prepared for the selected Shale, Coal and

Sandstone samples of the Bengal Basin, Bangladesh. The whole project is divided mainly into two parts including field work and laboratory work.

8 Once the laboratory work is finished, then the study concentrates for data analysis, publications and finally thesis writing. The research approach and design is shown in the flow chart (Fig.1.3).

1.3 Aims and Objectives

The aims and objectives of the current project can be showed briefly below:

a) To measure quantity, quality and thermal maturity of organic matter in shales, coals

and associated fine grained sediments.

b) To characterize biomarker distributions of the shales, coals and fine grained

sediments involved and to comment on their organic facies variations.

c) To identify kerogen types (organic matter) of the shales, coals and related fine

grained sediments.

d) To study macerals, microlithotypes and vitrinite reflectance of the shales, coals and

related fine grained sediments.

e) To explore depositional facies models of the coals.

f) To evaluate petroleum source rock potential and hydrocarbon generation-expulsion

of the shales, coals and fine grained sediments.

g) To examine the coal quality.

h) To characterize palaeodepositional environments of the shales, coals and related

fine grained sediments.

i) To identify minerals, cements, textures and thin section porosity in the sandstones.

j) To measure porosity, permeability and hydrocarbon saturation of sandstones using

well logs.

k) To evaluate reservoir quality based on petrography, diagenesis and petrophysical

study of the sandstones.

9 l) To put forward a final observation about the potential of the source rocks and

reservoir rocks of the Bengal Basin.

1.4 Limitations of the Study

The current research deals with nine gas fields and two coal basins of the Bengal Basin,

Bangladesh. However, considering the size of the Bengal Basin, the collected core samples of the studied gas fields and coal fields are not enough to evaluate the elements of petroleum system of the Bengal Basin. Sometimes, the collected core samples were old, broken and distorted which could have affected its insitu condition. The petrophysical analysis is dependent mostly on wire line log data with the help of limited core data.

Detailed analysis of some insitu properties (e.g., porosity, permeability, hydrocarbon saturation and water saturation of sandstone reservoirs; proximate analyses of coals) need more core samples from different depths to supplement the present study.

1.5 Outline of the Thesis

The Chapter 1 introduces the major issues concerning the current research project based on the Bengal Basin, Bangladesh. The background study with literature survey results are described in the Chapter 2. It is summarized separately on Shale, Coal and Sandstone aspects since different methodologies and explanations are drawn independently for each of them. The petroleum and coal resources of the study area and its related description are included in this Chapter 2. The sampling methods, sample size, sample cleaning, sampling depths and all laboratory analytical techniques are illustrated in Chapter 3. The detail results of the current project are described and discussed in Chapter 4. It is described in three sections, including ‘Shale’ as a petroleum source rock (4.1), ‘Coal’ as a petroleum source rock (4.2) and ‘Sandstone’ as a petroleum reservoir rock (4.3). Different

10 experiments and study methods are used for the current research based on different study materials. Accordingly, a section on ‘Discussion’ is added at the end of each of these sub- chapters. The major findings of the current research are summarized in Chapter 5.

Nonetheless, the future research is also suggested in the recommendation sub-chapter at the end followed by the Appendices and Bibliography.

The output of this research would add to the existing knowledge of the source rocks and reservoir rocks of the Bengal Basin, Bangladesh. It should be noted that a large portion of the findings of the current research project have already been published/accepted (including review stages) in different ISI/WoS (web of science) indexed journals (Appendices A1, A2,

A3, A4 and A5; A6, A7, A8 and A9) and also in several conference proceedings.

11 CHAPTER 2: LITERATURE REVIEW AND STUDY AREAS

Literature review offers an outline of the relevant and important current literature on the planned research area. The following review includes description and summary with their critical evaluations of the relevant materials. Finally, it finds the ‘gap’ where the special attention needs to address during the present study.

2.1 Previous Studies

2.1.1 Shale

Publications on shale of the Bengal Basin (Bangladesh) are scanty. A systematic study on the presence of bicadinanes and other terrestrial terpenoids in Oligocene Jenum Formation of the Bengal Basin was analyzed by Pearson and Alam (1993). Curiale et al. (2002) studied on the origin of petroleum in Bangladesh mostly based on molecular and isotopic compositions of the natural gas and condensates. They compiled a report on petroleum systems of the Bengal Basin, Bangladesh. Based on optical microscopy and XRD, the mineralogical composition of Surma Group shales was explored by Rahman and Faulp

(2003). A provenance study of the Surma Group shale has been carried out by Rahman and

Suzuki (2007a) on the basis of chemical and mineralogical compositions. Hossain et al.

(2009 and 2010) published papers on characterization of organic matter, depositional environments and provenance of the Tertiary mudstones from the Sylhet sub-basin of the

Bengal Basin. Geochemical methods (organic and inorganic) were used for identifying the quantity, quality and thermal maturity of the studied mudstones samples ranging from

Eocene Kopili to Pliocene Dupi Tila Formations. Takeda et al. (2011) worked on the geochemistry of the natural gas and condensates collected from the Surma sub-basin,

Bengal Basin. They found the coaly or terrestrial organic matter as the sources for these gas and condensates. None of the workers published any paper considering the detail

12 geochemistry and petrology of the Surma Group shales. The present research establishes the need for a detailed study on the geochemical and petrological characteristics of the

Surma Group shales, the Bengal Basin, Bangladesh.

2.1.2 Coal

There are several publications and reports on the Permian Gondwana coals of Bangladesh.

The Barapukuria and Dighipara Coal Basins were discovered by the Geological Survey of

Bangladesh (GSB) in 1985 and 1995, respectively. On the basis of exploration work including geophysical surveys and drilling results, Armstrong (1991) prepared a detail feasibility study report for the Barapukuria coal deposit, Bangladesh. The coal is now being extracted from the Barapukuria Basin using underground mining methods. The Dighipara

Coal Basin is still in the exploration stage. There is no published scientific work on

Dighipara before the present study. Bostick et al. (1991) published on petrography

(macerals assemblages) of the Barapukuria coal on the basis of semiautomated reflectance scanning. Akhtar and Kosanke (2000) and Akhtar (2001) analyzed the palynomorphs of

Permian Gondwana coals of the Barapukuria and discussed its paleoenvironments. As a partial study on Petroleum Systems of Bangladesh, Shamsuddin et al. (2001) discussed the source rock potential of the Gondwana coals of Bangladesh. They stated that coals in

Gondwana formations are at sufficient thermal maturity for hydrocarbon generation. Imam et al. (2002) published a paper on coal bed methane (CBM) prospect of the Permian

Gondwana coal of the Jamalganj Coal Basin, Bangladesh.

Hossain et al. (2002) worked on the sedimentary facies and palaeodepositional histories of the Permian Gondwana succession of the Khalaspir Coal Basin, northwest Bangladesh.

Rahman (2004) published on the importance of the utility of the Permian coal resources of

13 Bangladesh. From a structural and mining point of view, Islam and Islam (2005) worked on the water inrush hazard in the Barapukuria underground coal mine. Hasan and Islam (2003) published on the generalized subsurface geology and mineral resources of the Barapukuria,

Dighipara and Khalaspir coal basins of northwest Bangladesh. Based on elemental compositions, Islam and Kamruzzaman (2006) studied the geochemistry and techno- environmental issues related to mining and uses of Barapukuria coals. Islam and Hossain

(2006) worked on the lithofacies and Embedded Markov Chain analysis of the Gondwana sequence of the Barapukuria Basin, Bangladesh, dealing with the identification of lithofacies, their upward transition, cyclicity within the sequence and environments of deposition of the Gondwana sequences.

Islam and Hayashi (2008) published on geology and coal bed methane resource potential of the Gondwana Barapukuria Basin. The methane content of the bituminous coal at

Barapukuria ranges from 6.51 to 12.68 m3/t and it is represented as a potential resource of more than 5 Gm3 of gas. Farhaduzzaman et al. (2008) and Farhaduzzaman (2010) studied

Gondwana coal properties of Bangladesh. Measured ash, sulfur, calorific value, fixed carbon, volatile matter, moisture, average seam thickness and seam depth of Phulbari coal are 15%, < 1%, 6600 kcal/kg, 51.9%, 30.5%, 2.7%, 36m and 165-270m, respectively

(Farhaduzzaman et al., 2008). The total coal resource is 572 Mt at Phulbari. The coal is ranked as sub-bituminous to bituminous rank. They also showed the property of the

Barapukuria coal is quite similar with the Phulbari coal. Frielingsdorf et al. (2008) published a paper on tectonic subsidence modeling and basin development from a structural point of view based on the Gondwana coals from Kuchma, Singra and Hazipur wells of northwest Bangladesh. Recently, based on comprehensive desktop studies, UNDP (2008),

Muller (2009), Hildebrand (2010), Alam (2010) and Khalequzzaman (2010) discussed the

14 coal resources. They raised possibility of the challenges for coal bed methane (CBM), underground coal gasification (UCG) and mining development issues in northwest

Bangladesh.

There is no comprehensive analysis of the Permian Gondwana coals (Bangladesh) and its relation to other fine grained sediments based on organic geochemical and petrographical methods. The current study aims to fill this gap and undertakes to characterize the organic facies distributions within the Permian succession. It concentrates on the comprehensive analyses of coals, carbargillites and mudstones covering mostly all of the identified important seams of the Barapukuria and Dighipara Basins.

2.1.3 Reservoir sandstone

Several workers have published papers on sandstone analysis of the Bengal Basin,

Bangladesh. The petroleum reservoir sandstone of the Bengal Basin is primarily analyzed for reservoir quality as well as the diagenetic controls by Imam and Shaw (1985 and 1987) and Imam (1986 and 1989). Subsequently, Imam and Hossain (2002) discussed the hydrocarbon habitats in the Bengal Basin, Bangladesh. The reserves of natural gas and oil and the acting petroleum systems are highlighted in this dissertation. Based on formation velocity evaluation, Zahid and Uddin (2005) discussed the overpressure effect for the

Neogene strata of eastern Bengal Basin. Islam et al. (2006) have done petrophysical analysis of the reservoir sandstones from Titas Gas Field, the Bengal Basin. Rahman and

Suzuki (2007b) studied the provenance and tectonic settings on the basis of Surma Group sandstone geochemistry of the Bengal Basin. Najman et al. (2008) worked on the

Paleogene record of the Himalayan erosion based on the biostratigraphy and geochemistry of the Paleogene sediments of the Bengal Basin, Bangladesh.

15 Islam (2009) published on reservoir quality and diagenesis of the Bhuban Formation sandstones. Petrophysical evaluation of subsurface reservoir sandstones of the Bengal

Basin is carried out by Islam (2010a). Rahman et al. (2009) worked on the tidal sedimentation record of the Neogene Surma Group of the Sylhet Trough, the Bengal Basin.

Islam and Rahman (2009) carried out a geochemical analysis of the Miocene Surma Group sediments from Meghna Gas Field. Islam (2010b) studied the petrography and provenance of the subsurface Neogene sandstone reservoirs of the basin. A study on diagenetic history of the Surma Group sandstones of the Bengal Basin has recently been carried out by

Rahman and McCann (2012). Hossain (2012) published the latest oil reserves, albeit limited, of the Bengal Basin, Bangladesh. In the present research, sandstone petrography and XRD are used to study on reservoir quality and diagenesis effects to supplement all these studies. The petrophysical evaluation of the reservoir sandstone is also carried out and compared with the findings obtained from petrographic results.

2.2 Regional Geology and Tectonics

Guha (1978), Banerji (1984), Khan (1991), Reimann (1993), Khan and Chouhan (1996),

Alam et al. (2003), Uddin and Lundberg (2004), Imam (2005) and Steckler et al. (2008) studied the general geology and tectonics of Bengal Basin. Bangladesh lies in the northeastern corner of the Indian subcontinent at the head of the Bay of Bengal. It has

144,000 km2 of onshore and 63,000 km2 of offshore area. The basin occupies major part of the Ganges-Brahmaputra delta- the largest of its kind in the world by sediment load (some

1.6 billion tones per annum) carried to the sea (Reimann, 1993; Alam et al., 2003). The

Bengal Basin includes, in addition to Bangladesh, part of the Indian state of West Bengal in the west and Tripura in the east.

16 The basin is bordered to the west by the Precambrian Indian shield, to the north by the

Shillong Massif and to the east by the frontal fold belt of the Indoburman Range. It is open to the south for some distance to the Bay of Bengal (Fig.2.1).

Tectonically, the Bengal Basin evolved from collision of the Indian plate and the Asian plate. According to plate tectonic theory, the northwestern part of Bangladesh was initially joined along with Indian landmass, including Antarctica, Australia and others, forming a vast southern hemisphere super continent named Gondwanaland (Guha, 1978; Banerji,

1984; Khan, 1991). The southern part of the landmass of Bangladesh did not exist at that time. During the Cretaceous time (110 Ma), the Gondwanaland super continent began to break up and India began to drift towards north (Imam, 2005). The Bengal Basin was initiated during this time (Cretaceous) with rifting of the Indian plate from Antarctica.

However, the basin did not become center of deposition of thick clastic sediments until the northward drifting Indian plate collided with the relatively passive Asian plate (Khan and

Chouhan, 1996; Alam et al., 2003). It is only after this collision and minor uplift of

Himalayan Mountains that the remaining landmass of Bangladesh began to form.

The collision between Indian plate and Asian plate took place in stages beginning in

Eocene (55 Ma) when an initial uplift of the Himalayas occurred. By late Eocene (40 Ma), the last remnant of intervening Tethys Sea between Indian plate and Asian plate probably disappeared as a result of the collision (Uddin and Lundberg, 2004). During this time, the direction of Indian plate convergence changed from north to northeast with increasing collision with Asia. Since Oligocene (35 Ma), major sediments were shed off the rising

Himalayas as large river system started filling up the basin.

Fig.2.1. Location map of study areas including Barapukuria and Dighipara Coal Basins and nine gas fields. It shows the major tectonic elements of the Bengal Basin (modified after Khan, 1991; Reimann, 1993; Alam, et al., 2003; Shamsuddin et al., 2004; Imam, 2005).

18 During Neogene (onwards from 25 Ma), rapid rise in the Himalayas, accompanied by rapid subsidence in the basin to the south, resulted in deposition of a huge sedimentary pile with the simultaneous development of a mega delta. This became the land mass we now know as the Ganges-Brahmaputra delta.

The delta building activities continued along the central part of the basin, although the eastern part of the basin has since been uplifted into a folded mountain belt, i.e., Sylhet-

Chittagong Hills. It represents the frontal or outer western part of a more extensive orogeny, namely the ‘Indoburman Range’. The folded mountain belt resulted as a direct consequence of the subduction of the Indian plate beneath the Asian (Burmese) plate to the east. Alam et al. (2003) described the Bengal Basin as a ‘Remnant Ocean Basin’ which continued subduction along its eastern margin and incorporation of sediment complex into a westward migrating orogenic belt (Indoburman)- a process which will presumably result in the eventual closure and destruction of the basin. The tectonic framework of the Bengal

Basin can broadly be divided into two main units: (a) Stable Platform unit (Province 1) in the northwest, which further comprises two subunits- Rangpur Saddle and Bogra Shelf; and

(b) Deep Basin unit (Province 2) to the southwest-northeast, which also includes the Surma basin, Madhupur-Tripura Threshold, Faridpur Trough, Barisal High and Hatiya Trough in the west and the Fold Belt (Province 3) in the east. A third unit, a narrow northeast- southwest trending zone called ‘Hinge Zone’ (also known as Palaeocontinental Slope), separates the above two units diagonally almost through the middle of the country (Fig.2.1).

Above the basement in northwest Bangladesh, a number of half graben small basins like

Barapukuria, Phulbari, Khalaspir, Dighipara and Jamalganj occurred where sediments of the coal bearing Gondwana formations are present (Fig.2.2).

19 2.3 Study Areas and their Stratigraphic Frameworks

The Permian coal bearing Barapukuria and Dighipara Basins, northwest Bangladesh, are investigated in the present research. Also, nine gas fields covering the entire Deep Basin unit of the Bengal Basin, eastern Bangladesh, are examined in the current study (Figs.2.1 and 2.2). The detail of the study areas is discussed below.

2.3.1 Structure and Stratigraphy of the Barapukuria Coal Basin

The Barapukuria Basin is a north-south elongated coal bearing half-graben basin bounded by a major N-S oriented eastern boundary fault (Fig.2.3). The Gondwana sedimentary succession within the basin forms a singular asymmetric synclinal fold with ca. N10˚W trending axis. The axial plane dips towards the east (Imam, 2005). Stratigraphically, the

Barapukuria Basin includes Archaean, Permian, Tertiary and Quaternary formations representing the Basement Complex, Gondwana Group, Dupi Tila Formation and Barind

Clay (Madhupur Clay) Formation, respectively (Fig.2.4). The coal deposit is found within the Permian Gondwana Group (Armstrong, 1991; Islam and Islam 2005, Islam and

Hossain, 2006; Islam and Kamruzzaman, 2006; Islam and Hayashi, 2008). This sedimentary half-graben basin lies above the basement complex within which Permian age formations preserved by down faulting and subsequently infilled with unconsolidated

Tertiary and Quaternary sediments (Table 2.1). The lithostratigraphic description of the

Barapukuria Basin is stated below (from oldest upward).

21 2.3.1.1 Basement Complex (Archaean) in Barapukuria

The Archaean Basement Complex consists of various veined gneissic metamorphic and metaigneous rocks. There is some weathering at the top (5-10m), but below, these rocks are very strong and fresh. It has been considered to be eminently suitable for a wide range of uses as industrial aggregates.

Fig.2.2. The positions of Gondwana basins in the vicinity of the Barapukuria and Dighipara Coal Basins (after Uddin and Islam, 1992; Imam, 2005; Islam and Hayashi, 2008; Farhaduzzaman et al., 2012a).

2.3.1.2 Gondwana Group (Permian) in Barapukuria

The Permian Gondwana Group occupies an elongated sedimentary basin to the immediate west of a north-south geological fault, to the east of which is Archaean basement.

Fig.2.3. (a) Sampling locations shown in the study area of the Barapukuria Basin, Bangladesh. Two cross-sections have also been added- (b) west to east, and (c) north to south (Imam, 2005; Islam and Hayashi, 2008; Farhaduzzaman et al., 2013c and 2013d). The analyzed samples are collected from Seam VI, Seam V and Seam IV (Continued).

23 Fig.2.3 (Continued).

24 The full sequence is found only in the deepest part of the half-graben basin (approximately

450m) whilst in the peripheries only Seam VI and the underlying sediments are present.

Gondwana- ‘Lower Sandstone Sequence’

The sequence below Seam VI is substantially different from the Gondwana sequence above

(Table 2.1). It consists of a rapidly interbanded sequence of sandstones, siltstones and mudstones with occasional thin coal bands. Most of the sandstones above Seam VI are, to some extent, weathered and moderately weak, with slight to complete decomposition of the feldspars to kaolinitic clay. The sandstones below Seam VI, on the other hand, are mostly unweathered, less feldspathic and moderately strong. There are frequent units of fluviatile sandstones and interbanded sandstone-siltstone sequences with occasional thin bands of coals and isolated fossil plants. Tillites of glacial origin form the lowest part of the

Gondwana sedimentary sequence are generally considered to be of Upper Carboniferous age. They consist of variable thickness boulder-bed tillites containing clasts of unsorted sedimentary, igneous and metamorphic rocks, interbedded with occasional units of mudstone, siltstone and coal indicative of periods of interglacial sedimentation and occasional minor peat accumulations.

Gondwana- ‘Seam VI Sandstone Sequence’

This sequence varies from 75m to 125m in thickness and is of relatively homogeneous and massive light grey and white, medium to coarse grained sandstones, gritstones and conglomerates (Imam, 2005). The originally arkosic sandstones are strongly kaolinized, resulting in a white clay matrix almost throughout, greatly reducing their primary permeability. All of the sandstones in the Gondwana sequence contain occasional high angle joints.

25 These joints are generally tight or infilled, further limiting the sandstone’s secondary permeability, an important factor in terms of hydrogeology. Seam VI is the thickest seam

(average 36m) and apart from some thin impersistent bands of coal below, it is the basal coal seam in this sequence. It contains ˃ 90% of the Barapukuria coal reserves.

Gondwana- ‘Upper Coals Sequence’

The sequence is up to 180m thick and consists of an interlaminated sequence of fine to coarse quartzo-feldspathic sandstones with a number of coal seams (Seam I to Seam V) and occasional beds of siltstone and mudstone. The interlaminated nature of this sequence is very noticeable on the seismic sections. The sandstones close to the the base of the Dupi

Tila Formation are extremely weathered and there is slight to moderate weathering and kaolinization of the sandstones throughout the sequence.

2.3.1.3 Dupi Tila Formation (Mio-Pliocene) in Barapukuria

The Gondwana Group is unconformably overlain by Dupi Tila Formation (Table 2.1). This is comprised of grey to yellowish brown, medium to coarse, loose unconsolidated sands with clay-silt layers or gravels. The thickness is around 100-200m and it is the regional groundwater aquifer. The formation is divided into two units, namely, Lower Dupi Tila and

Upper Dupi Tila. The Lower Dupi Tila is characterized by firm, light grey and white clayey sands and kaolinitic clays which were probably derived from the weathering of the weak kaolinized Gondwana sandstones immediately below. Lower Dupi Tila is absent from the northern parts of the basin and generally thickens to the south where the main clay beds are interlaminated with loose silts and sands. Upper Dupi Tila is 107m thick on average and is divisible into lower and upper parts.

Fig.2.4. Generalized lithostratigraphic succession of the Barapukuria Basin, Bangladesh. (a) represents the central north-western part of the basin, and (b) represents the central south-eastern part of the basin (Fig.2.3 for its location). The sampling locations are also shown (Farhaduzzaman et al., 2012a).

27 The lower part of Upper Dupi Tila is approximately 40m thick and is composed of organic- brown, slightly micaceous sandstone, generally finer than the upper part with more frequent thin beds of silt and clay. The upper part of Upper Dupi Tila is 65m thick and is composed of micaceous grey sands and gravels with occasional bands of silt and clay.

2.3.1.4 Barind Clay (Pleistocene to Recent) in Barapukuria

The Upper Dupi Tila is overlain by the 3-15m thick Barind Clay (also known as Madhupur

Clay) that consists of yellow to reddish brown silty clay and overlain by a thin mantle (less than 1m) of alluvium and silty soil.

2.3.2 Structure and Stratigraphy of the Dighipara Coal Basin

Stratigraphy of the Dighipara coal basin has not been well established and it is still under exploration. However, on the basis of lithological logging and data collection while sampling (for current research) and during drilling, the following description has been prepared. The Dighipara Coal Basin is located within the southern slope of the Platform unit. The Dighipara Basin is a north-south elongated oval-shaped and fault bounded basin.

The eastern side of the basin might be fault bounded, as evidenced from the Bouger gravity anomaly map. The northeast-southwest trending fault may be the northern limit of the basin. The basin might have formed by faulting in the crystalline basement during Permo-

Carboniferous time (Banerjee, 1984). Later on, these basins were reshaped and basin marginal adjustments took place from time to time due to the Himalayan upheavals (Uddin,

1996). Subsequently, the Tertiary and Quaternary sediments were deposited over the crystalline basement within the half-graben basin. The quality of the Dighipara coal is similar to that of the Barapukuria coal (Alam, 2010). The Geological Survey of Bangladesh drilled four holes (as of December 2011) in the Dighipara and found coal in all holes.

Fig.2.5. Sampling locations in the study area of the Dighipara Coal Basin, Bangladesh.

The number of coal seams varies from three to seven whereby the top seams, A, B and C, constitute the majority of the resources. The coal is found at depths of 323-383m, which indicates the resource identified here is comparatively deeper than the Barapukuria. The cumulative thickness of the coal seams ranges from 47.32m to 71.07m, whilst the average thickness is 61 meters. The probable basin area is about 15 km2. The Bangladesh

Government has recently granted an exploration license to the Petrobangla. The Delta

Pacific Mining PLC has expressed their interest to have joint venture with Petrobangla.

The lithological descriptions and their corresponding stratigraphic positions of the geological formations are similar in comparison to those of the Barapukuria (Hasan and Islam, 2003). The sampling locations, boreholes and a simplified lithostratigraphic succession of representative bore holes of the Dighipara have been shown in Figs.2.5 and 2.6. The simplified lithostratigraphic descriptions of the

Dighipara Basin are stated below (from bottom upward).

Fig.2.6. Generalized lithostratigraphic columns of two investigated bore holes GDH60 and GDH62 of the Dighipara Basin. Sampling positions are also shown here.

2.3.2.1 Basement Complex (Archaean) in Dighipara

Gneissic and schistose metamorphic and meta-igneous rocks are the main constituents of the Basement Complex. Kaolinized weathering top is observed in this group whereas it is strong and fresh at deeper part. Gneiss, schist, granodiorite and quartz diorite are the common rock types.

31 2.3.2.2 Gondwana Group (Permian) in Dighipara

The Dighipara Gondwana Group consists of relatively homogeneous and massive light grey and white, medium to coarse grained feldspathic sandstones, gritstones and conglomerates.

Carbonaceous sandstone and carbonaceous shale is very common especially as roof and floor of the coal seams. The important Permian coal seams are hosted by this group of sediments.

Overlying the Gondwana Group, a silica sandstone with occasional clay beds, are observed in few of the GSB drill holes (Table 2.2) [Assumed to be the Paleocene Tura Formation (?)

(Hasan and Islam, 2003)]. On the other hand, reworked sandstone and shale with fossils is identified in some cases underlying this so-called Tura Formation. This is assumed to be

Kopili Formation (?) as stated by Hasan and Islam (2003). There is a great possibility that these so-called Tura and Kopili Formations could be the part of huge Gondwana Group sediments. However, it requires more study (palynology, geochemistry, isotopes) for further clarifications.

2.3.2.3 Dupi Tila Formation (Mio-Pliocene) in Dighipara

The Dupi Tila Formation unconformably overlies the Gondwana Group sediments (Table

2.2). It is basically unconsolidated sandstone, pebbly sandstone and occasional claystone.

The sandstone is light yellow to brown, white at places, fine to coarse and loose. The pebbly sandstone is grey with various shades of colour, sub-angular, mostly quartzite embedded in a sand matrix and is poorly consolidated. The clay is grey to bluish grey with reddish tints, sticky and plastic when wet, hard on drying, and at places, with lignitic material present. The bottom part is white and soft.

32 2.3.2.4 Barind Clay (Pleistocene to Recent) in Dighipara

The Barind Clay is red and brown, variegated, sticky and plastic when wet and hard on drying. Ferruginous nodules are present within this formation. It is overlain by a thin layer of Recent Alluvium consisting of silty clay with rootlets at the top.

2.3.3 Stratigraphy of the Deep Basin unit of the Bengal Basin

In contrast to Platform unit (a 400m thick sedimentary pile), the stratigraphy of the Deep

Basin unit of the Bengal Basin is characterized by an enormous thickness (up to 22km) of

Tertiary succession, the largest sedimentary accumulation in the world. In Platform unit

(Province 1), the stratigraphic succession includes Permian, Cretaceous and Tertiary rocks overlying Precambrian basement. On the other hand, in the Deep Basin unit (Province 2), this succession can be divided into the Jaintia Group (Paleocene to Eocene), Barail Group

(Oligocene), Surma Group (Miocene to Early Pliocene), Tipam Group (Middle Pliocene) and overlying Dupi Tila (Late Pliocene) and Madhupur Clay Formations (Plio-Pleistocene)

(Fig.2.7) (Alam et al., 2003; Imam, 2005). During the Tertiary period (2-65 Ma), the

Bengal Basin as it is today, started to form and a major part of the sedimentary succession was deposited in this time (Fig.2.8). Stratigraphy of the Deep Basin unit is dominated by deltaic to terrestrial (continental) clastic sedimentary rocks comprising mostly sandstone and shale. Recently, the open marine to shelf marine depositional environmental signatures have also been documented, especially for the Neogene sediments. However, the sedimentary succession encountered in the Deep Basin unit, described below, ranged from

Paleocene to Recent (Alam et al., 2003; Imam, 2005).

34 2.3.3.1 Jaintia Group (Paleocene-Eocene)

The Paleocene-Eocene marine Jaintia Group that is deposited under marine conditions can be divided into three formations (from bottom upward): Tura (Paleocene), Sylhet

Limestone (Middle Eocene) and Kopili (Upper Eocene) (Table 2.3). The Tura Formation is composed mainly of whitish sandstone with little shale and occasional coal beds near the top. The unit is drilled in several wells in the Platform area of the Bengal Basin and it is

150-350m thick. Only one isolated outcrop of this unit has been recorded in Sylhet-

Meghalaya (India) border and it represents the oldest exposed rock in Bangladesh. The overlying Sylhet Limestone Formation is a fossiliferous (Nummulitic) limestone unit with an average thickness of 250m. It is extensively developed and can be traced as a seismic marker horizon in Platform area of the Bengal Basin. Scattered small outcrops of this formation are observed along the Sylhet-Meghalaya (India) border close to Dauki fault. The overlying Kopili Formation is composed of dark grey to black fossiliferous shale with few limestone beds. This formation is around 40-90m thick and marks the end of open marine condition of deposition at the top.

2.3.3.2 Barail Group (Oligocene)

The Oligocene Barail Group is composed of alternating sandstone, shale, siltstone and occasional carbonaceous rich layers. In neighboring Assam, about 3000m of Barail sediments are recorded and this group is divided into three units from bottom upward: (a) the arenaceous Laisong Formation, (b) the argillaceous Jenum Formation and (c) the arenaceous Renji Formation. Most of the Barail Group sediments are deeply buried in

Bangladesh.

36 Fig.2.7 (Continued). Correlation of the studied ten wells (from north to south) of respective nine gas fields, the Bengal Basin, Bangladesh. All of the analyzed samples are collected from Boka Bil and Bhuban Formations lying at the bottom part (Moinul et al, 1977; Nazim et al., 1982; Khan, 1991; Alam et al., 2003; Imam, 2005; Farhaduzzaman et al., 2012b and 2013b).

Only two wells, i.e., Atgram IX and Rashidpur 2, penetrated 960m and 460m Barail sediments, respectively, at depths more than 4000m below the surface (Reimann, 1993). A small trip of land at Jaintia (Sylhet)-India border exposes about 350m of Barail (Renji

Formation) sediments and it represents the only Oligocene outcrop in Bangladesh.

2.3.3.3 Surma Group (Bhuban and Boka Bil Formations) (Mio-Pliocene)

The Surma Group, up to 5km thick, is composed of the Bhuban and Boka Bil Formations and is exposed in the Sylhet and Chittagong hills. Both formations are composed of sandstones and shales with siltstone and some conglomerates interpreted to have been deposited in a deltaic to shallow-marine environment (Holtrop and Keiser, 1970). All of the hydrocarbon accumulations so far discovered in Bangladesh have been found within the

Bhuban and Boka Bil Formation sandstones. The formations also contain shale intervals with important source rock potential (Imam, 2005). The overlying marine shale acts as a basin-wide seal.

The Tertiary succession in the Bengal Basin in Bangladesh can be correlated with outcrops in Lower and Upper Assam (India) which were studied and interpreted by Evans (1932).

However, this stratigraphic classification is based almost exclusively on lithologic characteristics (Das Gupta, 1977).

37 The subdivision of the monotonous and repetitive sand-shale sequence of Surma Group into the Bhuban and Boka Bil formations is often ambiguous in absence of diagnostic lithology

(Johnson and Alam, 1991; Alam et al., 2003; Imam, 2005). Correlation between the basins is made difficult because of the absence of marker horizons (Khan and Muminullah, 1980), diachronism of the units and lithological and facies variations (Das Gupta, 1982; Reimann,

1993). The deltaic Tipam Sandstone, for example, has been dated as Miocene in the Upper

Assam Basin, but as Pliocene in the eastern portion of the Surma sub-basin in the Bengal

Basin, Bangladesh. Within the Surma Group, the Bhuban Formation is in general more sand-rich and the Boka Bil Formation more argillaceous. Both formations show extensive lateral facies changes and vertical variations in sand: shale ratios, making difficult to correlate them across the basin (Johnson and Alam, 1991; Imam, 2005). Alam et al. (2003) emphasized that the contact between the formations is often difficult to recognize based on

Evan’s (1932) lithostratigraphic scheme.

Fig.2.8. Geological cross-section through the Platform (Province 1) unit and southern part of the Deep Basin (Province 2) unit of the Bengal Basin. The location of cross-section line has been shown in Fig.2.1 (after Alam et al., 2003).

38 2.3.3.4 Tipam Group (Pliocene)

Following the basin filling by deltaic deposits, a broad front of river plain environment was established under which sand dominating (arenaceous) units are deposited. This is recognized as Tipam Group, which can further be divided into three formations including

(from bottom upward) Tipam Sandstone Formation, Girujan Clay Formation and Dupi Tila

Formation (Imam, 2005). The Middle Pliocene Tipam Sandstone Formation (1200-2500m) is typically a grey brown, medium to coarse grained, cross-bedded to massive sandstone with minor intervals of clay layers. Overlying the Surma Group, it is extensively exposed in

Chittagong Hill Tracts area. The overlying Girujan Clay Formation (100-1000m) is a sticky bluish-grey clay unit that has a local extent and represents deposition in lake environments.

This unit is conformably overlain by sand dominating Dupi Tila Formation (500-3000m).

The Late Pliocene Dupi Tila is the sand dominated unit with minor interbedded claystone.

The sandstone within this formation is red to brown, medium to coarse grained, loosely compacted, cross-bedded, occasionally pebbly and contain petrified wood in places. This formation was deposited under fluvial/river plain environments. This is the regional and major groundwater aquifer in Bangladesh. The Dupi Tila Formation is sometimes considered to be a separate group (Alam et al., 2003).

2.3.3.5 Madhupur Clay Formation (Plio-Pleistocene)

Quaternary sediments are represented by the Madhupur Clay Formation overlying the Dupi

Tila Formation (Table 2.3). It is composed of reddish to brownish clay with subordinate silt and typically occurs in the uplifted terraces as well as in the subsurface. This unit is covered by a thin layer of Recent Alluvium sediments.

Fig.2.9. The petroleum systems of the Bengal Basin, Bangladesh. The estimated hydrocarbon resource is added (modified after Jamaluddin et al., 2001; Shamsuddin et al., 2004). 82 shale (SH), 33 sandstone (ST) and 36 coaly (CL) sampling numbers are also shown.

40 2.4 Coal Resources in the Bengal Basin, Bangladesh

Approximately three billion tons of Permian Gondwana coal resources (70 TCF gas equivalent) has been estimated in five coal basins discovered so far in Bangladesh. All of the recognized coal basins have been identified in the Platform unit of the Bengal Basin, northwest Bangladesh. The estimated coal resources include 1053 million tons (Mt) in

Jamalganj, 390 Mt in Barapukuria, 572 Mt in Phulbari, 685 Mt in Khalaspir and 600 Mt in

Dighipara Coal Basin (Farhaduzzaman et al., 2008). The identified coal is low ash, low sulfur and high volatile bituminous to sub-bituminous in rank (Imam, 2005). Together with power plant uses, it has the property to make coke which is an important fuel for steel industries. Starting from 2007, coal has been continuously extracted (1 Mt/a) from the

Barapukuria Underground Coal Mine, the only coal mine in the country.

2.5 Hydrocarbons in the Bengal Basin, Bangladesh

The Bengal Basin (Bangladesh) comprises two major petroleum provinces: (a) The Eastern

Foldbelt Petroleum Province and (b) The Western Petroleum Province (Fig.2.9). The

Eastern Foldbelt Petroleum Province is, so far, the only known proved petroleum system in the basin. The natural gas and condensates currently produced in Bangladesh come from anticlinal structures in the Eastern Foldbelt Petroleum Province of the Bengal Basin

(Jamaluddin et al., 2001). Here, Middle to Late Miocene reservoir sandstones are capped by

Upper Marine shales in the upper part of the Surma Group. Source rock intervals occur in the Middle Oligocene Jenum shales and the Miocene Surma Group shales. Estimated gas reserve (GIIP P+P) in Bangladesh is 28.42 TCF with 42 TCF undiscovered (Jamaluddin et al., 2001; Shamsuddin et al., 2004). Petrobangla re-estimated the total recoverable oil reserve of 137 million barrels STOIIP or STOOIP (Hossain, 2012).

41 Crude oil production took place here from 1987 to 1997. Currently, out of 25 gas fields

(including one minor oil field) so far discovered, only 20 are producing. The gas production started in 1959. Now the daily production of gas and condensate is approximately 2283

MMCFD (million cubic feet per day) and 7338 BBLD (barrels per day) respectively (04

April 2013, Petrobangla). The majority of gasfields in Bangladesh produce dry gas with a significant proportion of condensate (up to 18 barrels per million cubic feet of gas).

42 CHAPTER 3: MATERIALS AND METHODS

Assuming the nature of the working procedure, the materials and methods were divided into two main sections: (a) field work and sampling and (b) laboratory work.

3.1 Fieldwork and Sampling

After a through literature review, the project plan was finalized and accordingly, fieldwork was carried out in the Bengal Basin, Bangladesh. The rationale of the field work was to cover the entire Deep Basin unit and major coal fields of the Bengal Basin. Fifty six Boka

Bil shale, 26 Bhuban shale, 33 sandstone, 22 coal, 10 carbargillite and four mudstone core samples (full core with dimensions of 50mm x 45mm) were collected (all together 151 core samples) from the core laboratories controlled by Bangladesh Oil Gas and Mineral

Corporation (Petrobangla). However, some of the core laboratories (e.g., coal cores of

Dighipara Basin) were controlled by the Geological Survey of Bangladesh (GSB). In addition for a purpose of comparative assessment, five bulk coal samples were also collected from a stockpile of the Barapukuria half-graben basin whereas coal is currently being extracted through underground mining method. Each core sampling location was considered as a single depth instead of ‘from-to’.

Core samples were chosen from ten wells of respective nine gas fields. However, shale samples are chosen from eight wells of respective eight gas fields (Rashidpur, Patharia,

Fenchuganj, Bakhrabad, Titas, Kamta, Begumganj and Shahbazpur). Similarly sandstones are from eight wells of respective seven gas fields (Kailas Tila, Rashidpur, Fenchuganj,

Titas, Kamta, Begumganj and Shahbazpur). Five bore holes of two coal basins (DOB8,

CSE7 and CSE9 at Barapukuria; GDH60 and GDH62 at Dighipara) were selected for coal, carbargillite and mudstone sampling. The depth of shale sampling ranged from 998 to

43 3572m, 2398-3620m for sandstones and 133-469m for coals/coaly samples. All of the core samples and bulk samples were air dried and stored in core boxes made with tin or plastic.

Each core box contained one meter of core sample of shale, coal or sandstones. All of the core samples are cleaned properly after drilling. The collected core samples were again cleaned with wire brush and penknife for removing the surface contamination. Fig.3.1.1 displays typical samples of some of the shale (A, B and C), sandstone (A and D), coal (E and F) and mudstone (F) cores.

3.2 Laboratory Work

The core samples collected from the field were subjected to laboratory work using different modern standard analytical methods and techniques.

All 82 shale (Boka Bil 56 and Bhuban 26) and 36 coal and coaly samples were crushed into fine powder for analysis with a Source Rock Analyzer (SRA) in the Weatherford

Laboratories, USA. After SRA screening, 32 shale samples and 16 coal and coaly samples were selected for Soxhlet extraction followed by liquid column chromatography for fractionations. Subsequently, 30 shale (Boka Bil 16 and Bhuban 14) and 16 coal and coaly samples were investigated using gas chromatography mass spectrometry (GCMS). Ten shale, six coal, three carbargillite and two mudstone samples were analyzed by pyrolysis gas chromatography (PyGC) for kerogen quality. Among these samples, 11 shale and 15 coal samples were chosen for Rock-Eval pyrolysis for comparing with the results of SRA.

Forty shale (Boka Bil 20 and Bhuban 20) samples were used in parallel for elemental analysis. Eleven coal samples of the Dighipara Basin were analyzed by Atomic Absorption

Spectrometry (AAS) for elemental concentrations. 48 shale (Boka Bil 29 and Bhuban 19) and 36 coal and coaly samples were examined microscopically for maceral analysis.

44 Every coal samples were used for proximate analysis. All 33 sandstone samples were studied using petrographic microscope. Ten representative sandstone samples were analyzed with scanning electron microscope and XRD.

Fig.3.1.1. (A) Shale and sandstone core samples stored in core-box of BAPEX; (B) and (C) Shale core samples; (D) Sandstone core samples; (E) Coal core samples of the Dighipara Basin; (F) Coal core samples with organic-rich mudstone (top left at F) sample of the Barapukuria Basin.

45 The elemental analysis (EA), pyrolysis gas chromatography (PyGC), gas chromatography

(GC), gas chromatography mass spectrometry (GCMS), atomic absorption spectrometry

(AAS), thermogravimetry-differential thermal analysis (TG-DTA), XRD and microscopic studies were performed in different relevant laboratories at the University of Malaya,

Malaysia.

3.2.1 SRA and RE

The Weatherford Laboratories Instruments Source Rock AnalyzerTM (SRA) is designed to help identify and characterize source rock and reservoir rock by heating small amount (50-

100mg powder) of geologic samples (i.e., outcrops, cuttings, conventional cores and sidewall cores) to a programmed temperature in an inert atmosphere. Like Rock-Eval (RE) pyrolysis, SRA also determines the quantity, quality and thermal maturity of organic matter in sediments. Hence, the pyrolysis oven temperature is 750 ºC (850 ºC maximum) whereby the ramp rate is 25 ºC/minute (range 0.1 to 50 ºC/minute). The composition of the column is special tungsten alloy. The gas helium (GC zero grade), hydrogen (GC zero grade) or air

(GC zero grade) are used for the different required purposes during the analysis. Nitrogen or dry air is used for cleaning and cooling. It has a 100 position autosampler capacity which makes the procedure fast. The SRA quantitatively determines the amount of free hydrocarbons (S1) and the amount of hydrocarbons generated through thermal cracking of nonvolatile organic matter (S2) using a Flame Ionization Detector (FID). The amount of

CO2 produced during pyrolysis of kerogen (S3) is determined using an IR (infrared) detector. The SRA also determines the temperature at which the maximum release of hydrocarbons from cracking of kerogen occurs during pyrolysis (Tmax) and Total Organic

Carbon (TOC). Furthermore, it measures the hydrogen index (HI) and oxygen index (OI)

46 with good accuracy. A Weatherford SRA installed at the Geology Department, University of Malaya, is shown in Fig.3.2.1.

Fig.3.2.1. A Weatherford Source Rock Analyzer (SRA:TPH/TOC) installed at the petroleum geochemistry laboratory of the Geology Department, University of Malaya.

Rock-Eval 6 (RE-6) pyrolysis method was performed in the laboratory of Geotechnical

Services Pty Ltd, Australia. Rock-Eval pyrolysis has been widely used in the industry as a standard method in petroleum exploration (Espitalié et al., 1977 and 1984; Larter and

Douglas, 1980; Tissot and Welte, 1984; Peters, 1986). Like SRA, it is used to measure quantity, quality and thermal maturity of organic matter in sediments. This technique consists of the temperature programmed heating of a small amount of rock (100mg powder) in an inert atmosphere (Helium or Nitrogen) so as to determine the quantity of free hydrocarbons present in the sample (S1) and the amount of hydrocarbons (S2) and carbon

47 dioxides (S3) produced during the thermal cracking of the insoluble organic matter

(kerogen) in the rock. Nonetheless, Total Organic Carbon (TOC) content of the rock is determined by oxidation under air, in a second oven, of the residual organic carbon after pyrolysis (S4). In Rock-Eval 6, programmed heating of both the pyrolysis and the oxidation ovens is conducted from 100°C (instead of 180°C in the previous versions) up to 850°C

(instead of 600°C in the previous versions). By increasing the maximum pyrolysis temperature in Rock-Eval 6, the measure of the Hydrogen Index (HI) and oxygen index

(OI) are more accurate and the range of validity of Tmax is extended to higher values.

Fig.3.2.2. A Perkin Elmer 2400 elemental analyzer (CHNS/O) operated at the Chemistry Department of the University of Malaya.

48 3.2.2 Elemental Analysis (EA)

The powder samples are treated with 1M HCL in order to remove the inorganic carbonate.

The samples are then dried (Sia and Wan Hasiah, 2011). A small amount (1.5-2 mg) of dried sample is used for elemental analysis with a Perkin Elmer 2400 Elemental Analyzer

(CHNS/O) (Fig.2.2.2). The procedure is fully automated and includes a 60 position autosampler. In addition, it includes an intuitive, easy-to-use, EA Data Manager Software.

The EA Data Manager software adds a powerful capability that assists in streamlining the data collection and analyses. The CHNS analysis is accomplished by combustion at 925 ºC, reduction at 640 ºC, detector oven at 82.6 ºC, pressure 15 mmHg and a detector for 4000 counts. The sample is burned in an excess of high purity oxygen and various traps collected the combustion products namely carbon to carbon dioxide, hydrogen to water, sulfur to sulfur dioxide and nitrogen to nitric oxide. The masses of these combustion products are used to calculate the composition of the unknown samples. Helium is used as purge gas.

3.2.3 Bitumen (EOM) extraction

Extractable organic matter (EOM) or bitumen extraction is performed on approximately

15g of the powder samples using Soxhlet’s apparatus with an azeotropic mixture of dichloromethane (DCM) and methanol (CH3OH) (93:7) for 72 hours (Fig.3.2.3). Together with solvents (DCM and CH3OH), the EOM is evaporated using a water-bath evaporator until the majority of the solvent evaporates. After evaporation from water-bath, the EOM

(with some remaining solvent) is transferred to a measuring vial or in 10ml measuring cylinder. This vial (with EOM) is blowing with nitrogen gas until the rest little amount of solvent evaporates. Once all the solvent evaporates, then the EOM is measured.

49 3.2.4 Liquid column chromatography

The extracts (EOM) are separated by liquid column chromatography into aliphatic, aromatic and polar (NSO) fractions using the solvent petroleum ether, dichloromethane

(DCM) and methanol (CH3OH) respectively (Harwood and Moody, 1989) (Fig.3.2.4).

Fig.3.2.3. Bitumen (EOM) extraction in progress using Soxhlet’s apparatus; the sample is placed in a thimble.

However, at the start of this fractionation, the slurry is prepared by mixing silica gel and petroleum ether (petroleum benzine). A small volume of cotton wool is inserted at the bottom of the long column before pouring the EOM solution in the column. A small amount of alumina (2-3 cm) is also poured above the slurry inside the column. After this,

50 using 100ml petroleum benzine, the EOM solution is allowed to fractionate only the aliphatic fraction that is collected and weighed after blowing. Similar procedure is followed for separating aromatic and NSO fractions using the solvents DCM and CH3OH, respectively

Fig.3.2.4. Long column chromatography in progress for separating aliphatic (SAT) fraction. Petroleum ether solvent, silica gel, alumina and slurry are also shown at table.

3.2.5 Pyrolysis gas chromatography (PyGC)

Pyrolysis is simply the breaking apart of large and complex molecules into smaller and more analytically useful fragments by the application of heat (Harwood and Moody, 1989).

When heat energy applied to the molecule is greater than the energy of specific bonds,

51 those bonds will dissociate in a predictable and reproducible way. The smaller molecules generated by this bond-breaking are identified by the analytical tool selected with the help of understanding of the original macromolecule.

Fig.3.2.5. An Agilent 6890N Series gas chromatograph (GC) and gas chromatography mass spectrometer (GCMS). The Frontier Laboratories PY-2020iD model pyrolysis gas chromatograph (PyGC) unit shown here is also installed at the Geology Department, University of Malaya as an attachment.

In pyrolysis-gas chromatography (PyGC), the fragments generated by pyrolysis are passed through the GC for separation and identification. Frequently the major peaks in the resulting chromatogram (pyrogram) are easily identifiable and give direct structural information about the material being pyrolyzed. The pyrograms are more complex and serve as ‘fingerprints’ which may be used to distinguish related materials for identification or for quality control.

52 The number of peaks, the resolution by capillary GC and the relative intensities of the peaks permit discrimination among many similar formulations, making pyrolysis-GC a powerful tool in the identification of unknown samples.

Frontier Laboratories double-shot pyrolyzer PY-2020iD was used in this study. A 4-8mg

(4mg coal; 6mg carbargillite; 8mg shale/mudstone) solid whole rock sample (crushed powder) is used for the present analysis. The powder sample is inserted manually into the sample insertion port. An ultra-alloy capillary column specified with 30m length, 250µm nominal diameter and 0.25 µm nominal film thickness is used. A flow of helium flushes the pyrolyzates into the column where components are separated. The initial flow is 1.2

µL/min, with an initial pressure and average velocity of 13.3 psi and 29 cm/sec, respectively. The initial temperature is 54 ºC, ramping to the pyrolysis temperature of 600

ºC at a rate of 20 ºC/min. The total run time for analyzing a single sample is 95 minutes.

The detection method used is mass spectrometry and it is attached with GC/GCMS as described below (Fig.3.2.5).

3.2.6 Gas chromatography and gas chromatography mass spectrometry

Gas chromatography mass spectrometry (GCMS) is a method that combines the features of gas-liquid chromatography and mass spectrometry to identify different substances within a test sample. The aliphatic hydrocarbon fractions were analyzed using an Agilent 6890N

Series gas chromatography (GC) and gas chromatography mass spectrometry (GCMS). A manual syringe is used to inject small amount (1.0 µL) of the dissolved sample. The injected sample is vaporized and mixed with the He carrier gas. The vaporized mixture of sample and carrier gas is then moved through the capillary column.

53 The column is HP-5MS 5% phenyl methyl siloxane specified with 30m length, 250 µm nominal diameter and 0.25 µm nominal film thickness. The initial flow is 1.9 µL/min while nominal initial pressure and average velocity are 14.99 psi and 49 cm/sec, respectively.

Hydrogen, air and nitrogen gases are used for combustion for FID. A FID gas chromatograph with HP-5MS column, temperature programmed from 40 to 300 °C at a rate of 4 °C/min and then held for 30 min at 300 °C is used for GC analysis. GCMS analysis is performed using an Agilent V 5975B MSD mass spectrometer with a gas chromatograph attached directly to the ion source (70 eV EI mode). The total run time for GC/GCMS is 95 minutes. Fig.3.2.5 displays a GCMS together with Frontier Laboratories PY-2020iD model pyrolysis gas chromatograph (PyGC) unit installed at UM Geology Department.

Fig.3.2.6. The analytikjena contrAA®700 High Resolution Continuum Source Atomic Absorption Spectrometer (HR-CS AAS) installation at the Department of Geology of the University of Malaya.

54 3.2.7 Atomic absorption spectrometry (AAS)

Atomic absorption spectroscopy (AAS) is a spectroanalytical procedure for the quantitative determination of chemical elements employing the absorption of optical radiation (light) by free atoms in the gaseous state (Welz and Sperling, 2007). In analytical chemistry, the technique is used for determining the concentration of a particular element (the analyte) in a sample to be analyzed. In principle, it requires standards with known analyte content to establish the relation between the measured absorbance and the analyte concentration and relies therefore on the Beer-Lambert Law. In short, the electrons of the atoms in the atomizer can be promoted to higher orbitals (excited state) for a short period of time

(nanoseconds) by absorbing a defined quantity of energy (radiation of a given wavelength).

This amount of energy (i.e., wavelength) is specific to a particular electron transition in a particular element. In general, each wavelength corresponds to only one element and the width of an absorption line is only of the order of a few picometers (pm) which gives the technique its elemental selectivity. The radiation flux without a sample and with a sample in the atomizer is measured using a detector and the ratio between the two values (the absorbance) is converted to analyte concentration or mass using the Beer-Lambert Law.

The currently investigated samples are crushed into fine powder and then digested for AAS analysis. A small amount of sample (25mg) is dissolved with a mixture of hydrofluoric acid

(2ml HF), nitric acid (4ml HNO3) and hydrogen peroxide (2ml H2O2) using a Perkin Elmer

Microwave Reaction System. The power is 1000W with ramp of 10min. It is held on 50 minutes and then cooled for 20 minutes. Boric acid (12ml H3BO3) is also added for completion with 1200w power. It is held on for 10 minutes and then cooled for 5 minutes.

Nitric acid (6ml HNO3) is used for cleaning the digested solution.

55 Hence the power is 800W and held on for 5 minutes. It is finally cooled for 20 minutes in order to use in AAS.

The analytikjena contrAA®700 High Resolution Continuum Source Atomic Absorption

Spectrometer (HR-CS AAS) is used for the present analysis (Fig.3.2.6). Combined with an autosampler, the contrAA®700 works as a multi-element automatic setup for routine analytical jobs. An initial calibration is carried out on the elements under analysis by sequentially processing the related calibration standards at first and sequentially processing the actual samples in a second step. Hence, after each sample measurement, the results are available for all elements that are subject to analysis. The HR-CS AAS device consists of five basic modules such as light source, atomizer, monochromator, detector and evaluation unit (PC). A xenon short-arc lamp is used as the light source. It ensures the high radiation density and continuous emission throughout the entire spectral range (190-900 nm). The graphite tube atomizer and the burner and nebulizer system (BZS) are firmly installed in the sample compartment of the contrAAR®700. The selectivity of the analysis is realized by a high resolution double-monochromator (F=380mm) based on a prism and an Echelle grating monochromator. A low-noise and UV-sensitive semiconductor detector is used

(CCD line detector). ASpect CS 1.5 software is used for data analysis installed with the evaluation module. It supports the unique features of HR-CS AAS such as simultaneous background correction by acquiring spectral information in the vicinity of the analysis line, fast element/line change and the fast sequential multi-element measurement.

3.2.8 Polished block preparation for shale and coal samples for microscopic study

ICCP (1963) is followed for preparing the polished blocks. Approximately 20g hard coal

(or shale) is crushed into fine grains (2-3 mm diameter) using a mortar.

56 The crushed grains are then taken onto the bottom plate of a plastic mold and upper plate is placed surrounding the coal grains onto the bottom plate of the mold. The resin mixed with

2% - 3% hardener is poured onto the coal (or shale) grains in the mold as soon as possible.

The mold remains at room temperature for 24 hours so that the mold (coal or shale block) becomes ready for grinding and polishing. After 24 hours, the coal (or shale) block is removed from the mold. This block is then ground followed by polishing and shining. The coal (or shale) block is grinded using a diamond grinder in three stages: firstly, with coarse grains of carborundum so that the shale/coal surface becomes visible; secondly, with medium carborundum grains; and thirdly with fine carborundum grains. Finally, the block is smoothed with the finest powder used on a glass-plate. Water is slowly poured onto the block continuously during grinding/smoothing.

After grinding, the coal (or shale) block is polished manually sequentially using the 1 μm carborundum plate (with 1 μm powder), 0.3 μm carborundum plate (with 0.3 μm powder) and 0.05 μm carborandum plate (with 0.05 μm powder). Water is used with the powder when polishing. Finally, using the spongy plate with colloidal silica suspension, the coal/shale block is smoothed and shined for microscopic study. Nevertheless, the polishing is also carried out mechanically using the Buehler Beta Grinder-Polisher automatic polishing machine (Fig.3.2.7A). Firstly, three carborandum plates of different sizes (1 μm,

0.3 μm and 0.05 μm, progressively) are used onto the right wheel of the machine. In case of shale blocks, 2-propynol (iso-propynol) is used whereby water is used on coal blocks while polishing. Secondly, three similar carborundum plates of different sizes (1 μm, 0.3

μm and 0.05 μm, progressively) are used onto the left wheel of the machine. Thereafter, the

1 μm, 0.3 μm and 0.05 μm (respectively) suspension/gel is used on the corresponding plate while polishing. The force per unit area selected here is below 4 lbs in the machine.

57 The time is fixed at 20 seconds for each step. The coal/shale block is balanced and pressured using the legs of the machine. Some typical polished blocks are shown in

Fig.3.2.7B.

Fig.3.2.7. Polishing in progress with Buehler Beta Grinder-Polisher automatic polishing machine (A) and the polished coal/shale blocks (B).

3.2.9 Petrographic study of shale, coal and other coaly samples

The procedures, descriptions and analysis published by ICCP (1963 and its supplements

1985, 1986 and 1993) and ICCP System 1994 (1998 and 2001) are followed for

58 petrographic study of shale, coal and other organic-rich sediments. Petrographic examination is carried out using polished blocks (preparation details in subsection 3.2.8) under oil immersion in plane polarised reflected light.

Fig.3.2.8. A LEICA DM6000M microscope and LEICA CTR6000 photometry system equipped with fluorescence illuminators used at the Geology Department of the University of Malaya.

The LEICA DM6000M microscope and LEICA CTR6000 photometry system equipped with fluorescence illuminators was used for the present study (Fig.3.2.8). The filter system consists of BP 340-380 excitation filters, a RKP 400 dichromatic mirror and a LP425 suppression filter. Maceral compositions, based on a 1000 point count, are determined under both normal reflected ‘white’ light and ultraviolet light. Random vitrinite reflectance

(%VRr or %Ro) measurements in oil immersion are carried out in reflected ‘white’ light using the windows-based DISKUS Fossil software together with a Basler camera.

59 The DISCUS Macerals software attached with Basler camera is also used for point counting of different macerals and microlithotypes. Leica software along with Leica DFC camera is used for random analysis of macerals and for capturing photomicrographs.

Alternatively JENOPTIK ProGres® C3 is also chosen for capturing the photomicrographs.

At least 20, 500 and 1000 measurements per sample for shale/mudstone, carbargillite and coal samples respectively are taken while examination. The conventions of the 5% rule and the minimum band width (50×50 μm) are maintained during the microlithotype identification while the distances between points and between the lines of points are

0.5mm.

3.2.10 Themrogravimetry-differential thermal analysis (TG-DTA)

Thermogravimetric analysis or thermal gravimetric analysis (TGA) is a type of testing performed on samples that determines changes in weight in relation to a temperature program in a controlled atmosphere. A PerkinElmer Diamond TG-DTA is used for the proximate analysis (moisture, volatiles, fixed carbon and ash in percentages as stated by Earnest, 1988) of the studied coal samples. The simultaneous TG-DTA measures both heat flow and weight changes in a material as a function of temperature or time in a controlled atmosphere. The PerkinElmer Diamond TG-DTA analyzer consists of a high- precision balance with a platinum pan loaded with the sample. This pan resides in a furnace and is heated up to 1000 ºC with different required rates 10 and 20 ºC/minute or cooled during the experiment. The atmosphere is purged with inert gas helium to prevent oxidation or other undesired reactions. The gas (N, O, air) is used for the analysis. A computer is used to control the instrument. TGA is the process that utilizes heat and stoichiometry ratios to determine the percent by mass of a solute. After the data are obtained, curve smoothing and other operations are done to find the exact points of inflection. Fig.3.2.9A shows the

60 PerkinElmer Diamond TG-DTA analyzer installed at the Geology Department of the

University of Malaya. Fig.3.2.9B represents a typical TGA profile whereby the moisture content (%), volatile matter (%) and fixed carbon (%) of the analyzed coal sample are represented by the first, second and third weight loss steps respectively. The remaining weight at 950 ºC in oxygen corresponds to the ash content (%).

The coal samples were also analyzed from the laboratory of Minerals and Geoscience

Department Malaysia (ASTM D2013-07; denoted by JMG) for comparative assessments. It increases the data accuracy with high confidence.

3.2.11 Thin section preparation for sandstone samples

The procedure specified by Adams et al. (1988) is followed for thin section preparation. A slab of rock (1-2 mm thick) from the sandstone core is cut using a diamond saw. This slab is thoroughly cleaned and vacuum impregnated with low viscosity epoxy to fill the pores and mechanically support the specimen material. Using 100 micron particle size (120 grade) carborandum abrasive, one surface of the rock slab is ground flat on a piece of glass measuring about 30cm x 30cm and up to 1 cm in thickness. Only a small amount of carborandum (half a teaspoonful), just moistened with water, is used for grinding. After grinding with a rotary movement for about half a minute, the glass plate is washed and cleaned and fresh slurry of carborundum is placed on the plate.

When the surface of the rock sample becomes flat, it is thoroughly cleaned with a jet of water before grinding with the finer grade of carborundum. The second stage of grinding is carried out using 60 micron size (220 grade) carborundum and two periods of grinding, for about a minute each, with a fresh quantity of carborundum as required. After washing the

61 sample, a final grinding of one surface is made for about a minute with 12 micron size (3F grade) carborundum. Again after cleaning, the rock sample is polished using cerium oxide

(0.8 micron size).

Fig.3.2.9. A PerkinElmer Diamond TG-DTA installed at the Geology Department of the University of Malaya (A); A typical TGA profile whereby the moisture content, volatile matter and fixed carbon of the analyzed coal sample are represented by the first, second and third weight loss steps respectively; The remaining weight at 950 ºC in oxygen corresponds to the ash content in % (B).

Fig.3.2.10. Thin section preparation in progress operated at the Geology Department, University of Malaya.

The smooth surface of the rock sample is glued to a microscope slide using epoxy resin

(mixture of two fluids) with refractive index higher than 1.54. In case of few samples, the cover glass is attached with the help of the same epoxy resin. Moreover, in the process of fixing the rock to the microscope slide, care is taken to ensure that no air or gas bubbles are trapped between the cover glass and the rock. A thin section preparation in progress is displayed in Fig.3.2.10.

Fig.3.2.11. A Leica DMLP optical microscopes installed at the Geology Department of the University of Malaya; The PixeLINK digital cameras are attached for capturing images.

3.2.12 Petrographic study of sandstone samples

Petrography is the study of rocks and minerals using a microscope. In this study, thin sections were analyzed with a Leica DMLP microscope for polarization techniques in transmitted and incident light (please see 3.2.11 for thin section preparation). The

PixeLINK digital camera attached with the Leica DMLP microscope is used for capturing the images of the samples studied. The SWIFT (Model F) is used for point counting while the modal composition is achieved based on 600-point modal analysis per thin section.

SEM: Some of the selected sandstone samples were analyzed with JEOL JSM-7600F field emission scanning electron microscope (FESEM) operated in the Physics Department of the University of Malaya (Fig.3.2.12). The secondary electron detector mode is used for

64 capturing the images for the current analyses. Some of the images were taken with a

HITACHI 3000S scanning electron microscope (SEM) fitted with back scattered electron detector operated at the University of Tsukuba, Japan. It images a sample by scanning it with a beam of electron in a raster scan pattern. The electrons interact with the atoms that make up the sample producing signals that contain information about the sample's surface topography, composition and other properties such as electrical conductivity. High resolution examinations, up to 1,000,000 times magnifications with a resolution of up to 1.5 nanometers at 1.0 kV in GB mode, are carried out. The clay minerals, pore geometry, permeability, dissolution effect, cements, quartz overgrowth, texture and other related diagenetic imprints were investigated using the SEM.

3.2.13 XRD analysis

The clay minerals of the Tertiary sandstone and shale samples are studied using a

PANalytical Empyrean XRD equipped with PIXcel3D detection system located at the

Geology Department, UM. The PANalytical’s XRD software package (X’Pert HighScore) is used for identification, data collection and analysis of the clay minerals. Initially the samples are gently crushed into fine powder. The ˂ 2 µm fractions are then separated by centrifugation and are subsequently placed into a test tube mixed with distilled water. The dispersing reagent ammonia solution is mixed with the sample in test tube in order to prevent flocculation. The test tube (with sample solution) was kept at room temperature for

24 hours so that the finer clay fractionation settles at the top of the suspension.

Fig.3.2.12. A JEOL JSM-7600F field emission scanning electron microscope (FESEM) operated at the Physics Department of the University of Malaya.

The clay fraction at the top is then transferred by pipetting onto a small glass slide to prepare the XRD mounts. These mounts are then analyzed after air-drying and vapor saturation with ethylene glycol at 80 °C for one hour. The samples were also heated in two steps, to 350 °C and to 550 °C, in order to observe the changes in the XRD responses for different clay minerals present in the sandstones studied.

Fig.3.2.13. A PANalytical X-ray Diffraction (XRD) machine working at the Geology Department of the University of Malaya.

3.3 Software Used

3.3.1 ProSim ternary diagram

ProSim ternary diagram (France) is used to easily and quickly trace series of points or lines resulting from experimental data or calculations. It is always tiresome to plot a ternary diagram (tri-plot or triangular diagram) by hand. For this reason, ProSim develops for us an easy to use but powerful application enabling to create these diagrams in a few mouse clicks. In this case, the data used are always normalized. In order to have a relevant position of a point in the diagram, the sum of its coordinates must be equal to 1 (one). However, if we paste data from another software, the data can be provided in term of percentage. The

‘normalize data’ button leads to convert the whole series of points.

67 3.3.2 Didger 4

The printed hard copies of the studied well logs are scanned first using high quality scanner and then is made TIFF images for each logs required. The Golden Software’s Didger® 4 is used to calibrate and digitize geophysical well logs and export the information to an LAS file for the purpose of current analysis. In this case, well logs in TIFF format are converted to LAS files and subsequently studied by Excel software for petrophysical interpretation.

3.3.3 Excel software for petrophysical analysis

Archie (1942) introduced a classic empirical formula that is essentially related to formation conductivity, formation water conductivity and the formation resistivity factor (a function of porosity and cementation exponent) to the formation water saturation (Sw) and conversely hydrocarbon saturation (Sh). This formula applies satisfactorily to clean sands, whereas the presence of clay minerals (amount, type and distribution modes) has detrimental effect on the water saturation calculation. More than 30 water saturation models have been proposed to overcome the effect of shale for shaly sand reservoir evaluation

(Fertl, 1987). In most cases, hydrocarbon bearing clastic reservoirs are not free of clay minerals. The significant effects of these minerals on geophysical log responses are well recognized. The presence of shale (i.e., clay minerals) in a reservoir can cause erroneous values for water saturation and porosity derived from logs (Asquith and Gibson, 1982).

Hilchie (1978) notes that the most significant effect of shale in a formation is to reduce the resistivity contrast between oil or gas and water. The net result is that if considerable shale is present in a reservoir, it may be very difficult or perhaps impossible to determine if a zone is productive. He also suggests that shale content must be greater than 10 to 15% to significantly affect the log derived water saturation. The current analysis is based on the following procedures and formulas.

68 The hard copies of gamma (GR), resistivity (deep and shallow), sonic, SP, neutron, density, temperature and caliper logs were examined at the data center of the Bangladesh Petroleum

Exploration and Production Company Ltd (BAPEX), Petrobangla. Initial study regarding data quality, depth adjustment, sand and shale zone identification and quick look observation have been carried out on paper based logs. The scanned images (TIFF format) of all these well logs of Rashidpur 4 were collected from BAPEX for the present study.

These TIFF images have been converted to digital data (LAS format) using Didger®4 software. Subsequently, the digitized LAS files were transferred to Excel software and used for current analysis covering total gross thickness of 1463 m (depth 1310 – 2774 m) of the well Rashidpur 4.

Shale volume: Quantitative calculations of shale volume have been performed with the help of conventional techniques and formula introduced by Dresser Atlas (1979). Gamma ray logs are very good shale indicators and hence, calculation of the gamma ray index (IGR) is the first step needed to determine the volume of shale (Vsh) from a gamma ray log.

GRlog  GRmin GR                                     1 GRmax  GRmin

The volume of shale can be calculated mathematically from the gamma ray index for

Tertiary rocks (Dresser Atlas, 1979). This is a conventional formula that is used frequently to calculate shale volume in the petroleum industry and written as:

3.7IGR  Vsh  0.0832 1.0                               2

[Note: Please see the list of Symbols and Abbreviations for the descriptions of the symbols used here]

69 Porosity: After determining the volume of shale, it has been used to correct the porosity logs for shale effect. The density logs are used for porosity determination.

Dresser Atlas (1979) used the following equation to calculate porosity from density log:

             ma b  V  ma sh                           3 Den   sh      ma   f   ma   f 

Subsequently, the combined neutron and density log is used for getting the corrected porosity values (Schlumberger 1975):

    Nclay  Ncorr  N    0.30Vsh                                 4  0.45  

    Nclay  (5) Dcorr  D    0.13Vsh                               0.45  

 2  2   Ncorr Dcorr                                      6 N D 2.0

Thickness weighted average porosity (Bradley, 1987) is also measured as below:

Water saturation: After the log derived porosity correction for shale effect, the water

saturation was calculated using the neutron-density porosity (N D ). Following are the three more commonly used shaly-sand formulas for calculating water saturation (Sw):

70 2  2   0.4 R  V  V  5 S   w    sh   sh                         8 w  2          Rsh Rsh Rt  Rw     

2 1  R  aV  aV  S    w   sh   sh                       9 w  R 2 2  t   

V  2  sh  R 0.2 R 1.0 V  R S  sh w sh t                      10 w  2

0.4 Rw 1.0 Vsh 

Equation (8), (9) and (10) were introduced by Simandoux (1963), Fertl (1975) and

Schlumberger (1975), respectively. Thickness weighted average water saturation is calculated using the following formula given by Bradley (1987).

Formation water resistivity: Formation water resistivity (Rw) of the hydrocarbon bearing zone has been calculated from the formula given by Bateman and Konen (1977).

 SSP   logRmf   K  Rw 10                                      12

Where, SSP = Static spontaneous potential =  klog (Rmf / Rw)

K= 60+ (0.133 Formation temperature)

71 Rmf = RTemp(Temp + 6.77)/(TF+6.77)

Rmf or RTf = resistivity of mud filtrate at formation temperature

TF =Formation temp = (Hole temp  Surface temp) (Required depth / Total depth)

Permeability: Permeability (K) has been calculated from the following formula given by

Coates and Dumanoir (1973):

2  C 2w  K                                     13  4     w R w /Rtirr 

1  logR /R  2.22  2 Where, W  3.75   w tirr    2 

2 C  23  465ρh 188ρh

Permeability has also been calculated using Wyllie and Rose’s (1950) formula:

3 2 K  79  /Swirr  (dry gas)------14

Thickness weighted average permeability is measured as stated below (Bradely, 1987).

Hydrocarbon moveability: Comparative analyses were carried out for the calculated water saturation, hydrocarbon saturation and permeability of the studied reservoir. The arguments in favour of suitable approach have also been put forward. Movability of hydrocarbon is

72 also brought to notice with the aid of water saturation ratio of uninvaded zone and flushed zone; the expression of the formula is as follows (Asquith and Gibbson, 1982):

1/ 2 S  R / R  w   xo t                                    16     S xo  Rmf / Rw 

Bulk volume of water: The bulk volume of water of the hydrocarbon bearing zones in the studied well has been calculated using Morris and Biggs (1967) formula:

BVW  Sw                                      17

3.3.4 EndNote, StyleWriter and Turnitin

EndNote X5 software is used for bibliography management. The English grammar is checked with StyleWriter 4. The originality of the write-up is evaluated using Turnitin which is an important tool for checking the plagiarism of the work. The related reports are attached in Appendices F1, F2 and F3.

CHAPTER 4: RESULTS AND DISCUSSION

4.1 Petroleum Source Rock- Shales

4.2 Petroleum Source Rock- Permian Coals

4.3 Petroleum Reservoir Rock- Sandstones

74 CHAPTER 4.1 PETROLEUM SOURCE ROCK- SHALES

With respect to petroleum geology, the Bhuban and Boka Bil Formations are the most important stratigraphic units of the Bengal Basin, Bangladesh. These formations contain all the petroleum resources discovered so far. They are composed mainly of alternating shales and sandstones. The shales have long been considered as source rocks and the sandstones as reservoirs. The present study reports on an investigation of potential source beds within these two formations. For the present study, 82 drill core samples were collected from eight gas fields of the basin. Kerogen facies and thermal maturity are studied using geochemical and petrographical techniques.

4.1.1 Source rock properties

The results gained from Source Rock Analyzer (SRA) are shown in Table 4.1.1. Rock-Eval pyrolysis (RE) results of some selected samples are also displayed in Table 4.1.2 for comparative assessment. There is a good agreement between the results obtained from SRA and those of RE, raising the confidence in the SRA results. Most samples are organic lean

(<1%). TOC increases with depth (Appendix C1). The source rock potential of the analyzed shales is evaluated from the cross-plot of S2 (mg HC/g rock) versus TOC (wt.%) following the classification published by Peters and Cassa (1994) (Fig.4.1.1). HI values of Bhuban

Formations and Boka Bil Formations vary from 55 to 231 and 55 to 162 mg HC/g TOC respectively. Poor to fair source poetical is estimated by the Bhuban Formation. The Boka

Bil Formation shows mostly poor potential for hydrocarbon generation. Most of the

Bhuban samples plot in the Type III range but a few containing mixtures of Type II show notable variations, inferring a mixture of kerogen types (III/II). The Boka Bil samples represent mostly Type III kerogen. (Fig.4.1.2). The recorded OI values of Bhuban and Boka

Bil shales range from 60 to 228 and 62-228 mg CO2/g TOC, respectively.

77 The cross-plot of HI versus OI (modified van Krevelen diagram) reveals mostly Type III character of both formations (Appendix C2). Tmax values vary considerably ranging from

420 to 441 °C in Bhuban and 420 to 440 °C in Boka Bil Formation.

Fig.4.1.1 Cross-plot of total organic carbon (TOC in wt.%) and remaining hydrocarbon potential (S2 in mg HC/g rock) of the studied samples. Bhuban formation shows poor to fair quality source potential while Boka Bil shows mostly poor quality (adopted from Peters and Cassa, 1994; Dembicki, 2009).

The measured total sulfur percentage of the analyzed shale samples is very low. It ranges from 0.01 to 0.08% (Bhuban Formation) and 0.01 to 0.02% (Boka Bil Formation). Total nitrogen varies from 0.07 to 0.43% in the Bhuban and 0.12 to 0.43% in the Boka Bil. The ratio of C/S ranges from 4.2 to 128.6% in the analyzed Bhuban shales whereas 2.4 to 53.3% in the Boka Bil shales (Table 4.1.3). The measured C/N ratio varies from 0.6 to 13.3% and

0.8 to 4.2% in the Bhuban and Boka Bil, respectively. These values are typical of terrestrial organic matter deposited in a non-marine environment. Environment implications are discussed more thoroughly in section 4.1.4.3.

4.1.2 Maceral characteristics and kerogen type

Vitrinite is the dominant maceral group found in both of the analyzed Bhuban and Boka Bil samples followed by liptinite and inertinite (Table 4.1.4). Vitrinite is identified by its moderate grey color reflectance under normal reflected white light. In mineral free basis, it ranges from 62 to 80 (vol.%) and 64 to 83 (vol.%) in the studied Bhuban and Boka Bil shale samples, respectively. Vitrinite macerals are mostly distorted because of the bitumen staining, which is commonly observed in association with vitrinites (Fig. 4.1.3A and B).

Wood fragments are present in all the analyzed samples (Fig. 4.1.3C and D). Inertinite maceral ranges 7-14 vol.% in the studied Bhuban Formation and 5-15 vol.% in Boka Bil

Formation. Inertinite is distinguished by its higher reflectance and characteristic whitish color under normal reflected white light. Fusinite, semifusinite and inertodetrinite are the most common inertinite macerals observed in the studied samples (Fig.4.1.3E and F).

79 Both vitrinite and inertinite macerals are dark under ultraviolet light. But liptinite macerals show characteristic fluorescence under ultraviolet light (Figs.4.1.4 and 4.1.5).

Fig.4.1.2. Distribution of vitrinite reflectance (%Ro ) and Tmax (°C) plotting with hydrogen index (HI) of the analyzed samples. Bhuban formation depicts Type III/II (gas-oil prone) kerogen whereas Boka Bil is of Type III. Both formations are within immature to early mature oil window (see Appendices B1 and B3 for definitions) (modified from Peters and Cassa, 1994; Koeverden et al., 2011; cited by Farhaduzzaman et al., 2013a and 2013e).

Fig.4.1.3. (A) Moderately reflecting vitrinite (vt) which is associated with bitumen staining (bs) and white color inertinite maceral inertodetrinite (id) and pyrite (py) observed in Bhuban Formation, depth 3173m in well Fenchuganj-2. (B) Bitumen stained vitrinite associated with pyrite (py) observed in Boka Bil Formation, depth 2301.2m in well Bakhrabad-9. (C) Dark brownish color woody fragment (wf) found in Bhuban Formation, depth 3100m in well Begumganj-1. (D) Light brownish color woody fragment observed in Boka Bil Formation, depth 2296.5m in well Shabazpur-1. (E) Whitish color inertinite maceral fusinite (fs) identified in Bhuban Formation, depth 3172m in well Fenchuganj-2. (F) Whitish color inertinite maceral fusinite (fs) identified in Boka Bil Formation, depth 1777.3m in well Shahbazpur-1 [all photomicrographs shown are taken in normal reflected white light using oil immersion objective].

Fig.4.1.4 (A1) Moderate brown color liptinite maceral resinite (re) under normal reflected white light observed in Boka Bil Formation, depth 1834m in well Patharia-5. (A2) Same view as A1 under ultraviolet light which shows yellow fluorescence. (B1) Moderate brown color liptinite maceral resinite (re) under normal reflected white light observed in Bhuban Formation, depth 2714.2m in well Titas-11. (B2) Same view as B1 under ultraviolet light which shows yellow fluorescence. (C1) Brownish color liptinite maceral cutinite (ct) under normal reflected white light observed in Boka Bil Formation, depth 2329.6m in well Bakhrabad-9. (C2) Same view as C1 under ultraviolet light which shows yellow fluorescence.

Fig.4.1.5 (Caption continued next page)

85 Fig.4.1.5 (Continued). (A1) Dark brown color liptinite maceral resinite (rs) under normal reflected white light observed in Bhuban Formation, depth 2727.4m in well Titas-11. (A2) Same view as A1 under ultraviolet light which shows greenish yellow fluorescence. (B1) Dark brown resinite (rs) under normal reflected white light noted in Boka Bil formation, depth 2316m in well Shahbazpur-1. (B2) Same view as B1 which shows intense yellow fluorescence under ultraviolet light. (C1) Brownish color liptinitic amorphous (am) component under normal reflected white light viewed in Bhuban Formation, depth 3139m in well Kamta-1. (C2) Same view as C1 under ultraviolet light and it shows brownish yellow fluorescence. (D1) Brownish color liptinitic amorphous (am) maceral which could be of alginite origin under normal reflected white light saw in Boka Bil Formation, depth 3163m in well Patharia-5. (D2) Same view as D1 under ultraviolet light and it shows greenish light yellow fluorescence.

Liptinite content was determined from petrography as 11 to 24 and 10 to 21 vol.% in the analyzed Bhuban and Boka Bil shales, respectively. The important liptinitic macerals include resinite (Fig.4.1.4 A1 and A2; B1 and B2; Fig.4.1.5 A1 and A2; B1 and B2), cutinite (Fig.4.1.4 C1 and C2), amorphous organic matter (Fig.4.1.5 C1 and C1; D1 and

D2), liptodetrinite and alginite (trace amount). Nevertheless, similar types of maceral assemblages are observed in both of the analyzed Bhuban and Boka Bil Formations.

Giraud (1970), Larter and Douglas (1980), Dembicki et al. (1983) and Dembicki (2009) have all noted that pyrolysis-GC helps to interpret kerogen mixtures. This can give a direct indication of HC likely to be generated. According to the interpretation by Dembicki

(2009), C15 mode. For Type I kerogens, the situation is reversed. An intermediate situation represents

Type II kerogens (Dembicki, 2009). Unimodal fingerprints of predominantly n- alkane/alkene doublets with some specific abundant aromatic compounds displayed by whole rock PyGC pyrograms (Fig.4.1.6 and Appendix C3) suggest mixed kerogen sources of Bhuban and Boka Bil samples, possibly reflecting 75% Type III and 25% Type II input

(Dembicki, 2009). The ratio of n-octene (C8) to xylene (m+p) is applied as a measure of the comparative abundance of aliphatic to aromatic hydrocarbons (Aarssen et al., 1992).

86 The measured C8/xylene ratio of the analyzed Bhuban and Boka Bil samples varies from very low to moderate (0.56-1.78) (c.f., Solli et al., 1984). The high relative abundance of specific aromatic hydrocarbons (benzene, toluene and xylene) and low ratio of cadalene to xylene (Cd/xylene) (0.06 to 0.12) are consistent with dominant input from vascular higher plants in a terrestrial depositional setting.

Fig.4.1.6. PyGC pyrograms of Boka Bil and Bhuban shales (RP4SH1 and FN2SH9) display a mixed kerogen of Types III and II.

4.1.3 Soluble extract and biomarker distributions

Aromatic hydrocarbon dominates over the aliphatic hydrocarbons in both of the analyzed formations. Measured aromatic hydrocarbon is 13-126 mg/g TOC in Bhuban Formation

88 and 27-184 mg/g TOC in Boka Bil Formation. Aliphatic fraction varies from 3 to 54 mg/g

TOC in Bhuban and 2 to 115 mg/g TOC in Boka Bil. The measured total soluble hydrocarbon yields are in the range of 16-139 and 35-282 mg HC/g TOC in the analyzed shales. The total soluble extract ranges from 132-2814 ppm (Bhuban) and 235-1381 ppm

(Boka Bil) in the analyzed samples. Besides, the high extract found in sample T11SH59 and T11SH68 possibly marks the presence of some migrated bitumen. It might have happened since this geological unit is now hosting and producing gas at this field.

GC and GCMS analyses are carried out for the aliphatic fractions of the studied shale samples. The TIC (total ion current), m/z 191 and m/z 217 chromatograms are used to gather data reported here. The identifications of the peaks of these traces are made from retention times and published available literatures. For example, Waples and Machihara

(1991), Hossain et al. (2009) and Wang et al. (2011) are used for TIC; Ahmed et al. (2009),

Kashirtsev et al. (2010) and Hakimi et al. (2011) for m/z 191 fragmentograms; Pearson and

Alam (1993), Wan Hasiah (1999a) and Fabianska and Kruszewska (2003) for bicadinane and oleananes; and Abeed et al. (2011), Koeverden et al. (2011) and Sachse et al. (2012) for m/z 217 fragmentograms. Identity of these peaks and related other terms are described in

Appendices B1 and B2.

4.1.3.1 GC: TIC (Total Ion Current)

In most of the analyzed samples, the odd carbon homologs dominate over the even carbon homologs. However, the even carbon homologs also dominate over the odd carbon homologs in n-alkane of some other samples (Appendix C4).

The pristane/phytane ratio is high to very high varying from 0.99 to 3.41 in Bhuban shales and 0.58 to 3.65 in Boka Bil shales. The unimodal distributions of n-alkanes from C10 to

C35 with the maxima standing at C16 (mostly) or C18 are observed in the gas chromatograms

91 (TIC) of the analyzed Bhuban and Boka Bil shale samples. The calculated CPI1 values are close to unity. CPI1 is from 0.88 to 1.18 (CPI2 0.96-1.37) in Bhuban shales and 0.68 to 1.47

(CPI2 0.58-3.65) in Boka Bil shales (Table 4.1.5). Fig.4.1.7 and Appendix C5 display chromatograms of two representative immature samples of Boka Bil Formation. Fig.4.1.8 and Appendix C6 represent two mature samples of the same formation. Similarly, Fig.4.1.9 and Appendix C7 display chromatograms of two representative immature samples of

Bhuban Formation. Fig.4.1.10 and Appendix C8 represent two mature samples of Bhuban.

4.1.3.2 GCMS: m/z 191 Fragmentogram

Abundant pentacyclic triterpanes (hopanes and moretanes) are dominated by C30αβ-hopane in all the analyzed Bhuban and Boka Bil shale samples (Figs. 4.1.7, 4.1.8, 4.1.9 and 4.1.10).

Homohopanes are lower in concentration but dominated by C31-hopane in both of the formations. The R-isomers are dominant over the S-isomers among the homohopanes (C31 -

C33) of some analyzed Bhuban and Boka Bil shale samples (Figs.4.1.7B and 4.1.9B). It indicates that the samples are thermally immature for hydrocarbon generation. On the other hand, the S-isomers are dominant over the R-isomers in some other samples (Figs.4.1.8B and 4.1.10B). This again suggests the samples are thermally mature for hydrocarbon generation. A large amount of moretanes is also present in the studied samples. In general,

αβ-hopanes are more prominent than the βα-hopanes (moretanes). Sterane profusions are generally low (Figs.4.1.7C, 4.1.8C, 4.1.9C and 4.1.10C) consistent with dominantly terrestrial input (c.f., Peters and Moldowan, 1993). The Ts/Tm ratio of the studied samples ranges from 0.09-0.87 in Bhuban and 0.12-1.86 in Boka Bil samples.

Fig.4.1.7. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Boka Bil sample (SB1SH29). It represents immature oil window (peak i.d. in Appendix B2).

Fig.4.1.8. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Boka Bil sample (SB1SH48). It represents mature oil window (peak i.d. in Appendix B2).

Fig.4.1.9. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Bhuban sample (KM1SH2). It represents immature oil window (peak i.d. in Appendix B2).

Fig.4.1.10. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Bhuban sample (T11SH68). It represents mature oil window (peak i.d. in Appendix B2).

96 C30 moretane/C30 hopane and C32 22S/(22S + 22R) range from 0.09 to 0.44 and 0.43 to

0.63, respectively, for the analyzed Bhuban Formation shales (Table 4.1.6). Similarly, C30 moretane/C30 hopane and C32 22S/(22S + 22R) range from 0.05 to 0.36 and 0.43 to 0.65 respectively for the analyzed Boka Bil Formation shales. It is noted that the values of these features are very close to each other comparing with Bhuban and Boka Bil samples analyzed. Considerable abundances of 18α(H)-oleanane (higher plant marker) are found in all the studied samples. 18β(H)-oleanane is also identified in some of the analyzed samples.

The calculated ol/C30-hoapne (oleanane index) varies from 0.04 to 0.33 and 0.05 to 0.61 in the analyzed Bhuban and Boka Bil shales, respectively. Bicadinane (both T and R configurations) is identified in all the analyzed shale samples. The measured bc/C30-hopane ranges from 0.02 to 0.11 (Bhuban) and 0.02 to 0.65 (Boka Bil). These values are plotted against the vertical depth profile (sample names shown here) of the study area (Appendix

C9). The trend lines for both bc/C30-hopane and ol/C30-hopane values for Bhuban and

Boka Bil formations do not show any definite agreement rather having inverse correlation each other. The trend line for bc/C30-hopane shows better agreement with its data point where R2= 0.3685 having negative gradient and it decreases with depth. On the other hand, the trend line for ol/C30-hopane shows insignificant agreement among its data points irrespective of formation where the trend line shows positive gradient and R2= 0.0065. It increases with depth profile.

4.1.3.3 GCMS: m/z 217 Fragmentogram

C29 sterane is the dominant component noted in the m/z 217 mass fragmentograms. These are dominated by regular steranes compared to diasteranes of the analyzed Bhuban and

Boka Bil shale samples (Figs.4.1.7C, 4.1.8C, 4.1.9C and 4.1.10C and Appendices C5, C6,

C7 and C8). The most commonly used sterane parameters include C29 20S / (20S + 20R),

97 C29 ββ / (ββ + αα), sterane C27 / (C27+C29), diasteranes / steranes and diasterane 20S / (20S

+20R). The values range from 0.03 to 0.37, 0.29 to 0.50, 0.20 to 0.48, 0.05 to 0.42 and 0.13 to 0.70, respectively, in the analyzed Bhuban shale samples. These parameters in the analyzed Boka Bil shale samples range from 0.03 to 0.38, 0.04-0.48, 0.23 to 0.64, 0.04-0.49 and 0.17-0.80, respectively (Table 4.1.7). The sterane abundance is very low compared to hopane compounds, marking the influence of mostly terrestrial organic matter (Huang and

Meinschein, 1979; Peters et al., 2005).

4.1.4 Discussion

4.1.4.1 Thermal maturity

A thermally immature to early mature oil window was determined both for the examined

Bhuban Formation and Boka Bil Formation shales, as shown by randomly measured mean vitrinite reflectance and Tmax values. The measured mean vitrinite reflectance value ranges from 0.48 to 0.71 %Ro in the analyzed Bhuban shales and 0.48 to 0.70 %Ro in the analyzed

Boka Bil shales. This implies the thermal maturity condition of the analyzed shale samples varies from immature to early mature for hydrocarbon generation (see Appendix B3 for standard parameters and their corresponding values) (Peters and Cassa, 1994). The Tmax value obtained from SRA and RE ranges from 420 to 441 °C (Bhuban) and 420 to 440 °C

(Boka Bil) indicates the analyzed Bhuban and Boka Bil shale samples are of thermally immature to early mature oil window, in good agreement with the interpretation made from vitrinite reflectance values (Farhaduzzaman et al., 2012d). The recorded production index

(PI) value ranges from 0.11-0.40 in the analyzed Bhuban shales and 0.15-0.30 in Boka Bil shales, suggesting immature to early mature oil window conditions (Peters and Cassa,

1994).

98 The thermal maturity linked features of hopanes, steranes and diasteranes of the analyzed

Bhuban and Boka Bil shales are mostly either at or close to their thermal equilibrium values. Commonly C31- or C32-homohopanes are used for calculations of the

22S/(22S+22R) ratio. This ratio rises from 0 to about 0.65 while 0.57 to 0.62 is the equilibrium range commonly observed during maturation (Seifert and Moldowan, 1986).

The calculated ratio values are of 0.33-0.63 (Bhuban) and 0.33-0.65 (Boka Bil) for the studied shale samples falling within and outside the equilibrium range. Thus demonstrate the thermal maturity condition has reached partly, i.e., it represents immature to early mature oil window. For example, the analyzed Boka Bil shale sample SB1SH29 with the values of Tmax 430 ˚C, vitrinite reflectance 0.54 %Ro and C32 22S/(22S+22R) 0.50 demonstrate the sample is thermally immature. A similar immature thermogenic condition is also indicated by another Boka Bil sample PT5SH10 with the values of Tmax 433 ˚C, vitrinite reflectance 0.57 %Ro and C32 22S/(22S+22R) 0.48. But, the explored Boka Bil sample SB1SH48 with the values of Tmax 440 ˚C, vitrinite reflectance 0.65 %Ro and C32

22S/(22S+22R) 0.58 indicates the sample is thermally early mature for hydrocarbon generation. A similar early mature thermogenic condition is also suggested by another

Boka Bil sample BK9SH71 with the values of Tmax 437 ˚C, vitrinite reflectance 0.65 %Ro and C32 22S/(22S+22R) 0.57. However, the analyzed Bhuban shale samples KM1SH2 and

FN2SH7 correspond to immature oil window considering the maturity dependent factors

(i.e., vitrinite reflectance, Tmax, and biomarker ratio). Conversely, the analyzed Bhuban samples T11SH68 and BG1SH6 represent the early mature thermogenic condition for hydrocarbon generation following these evaluating parameters above. Mackenzie et al.

(1980) reported the ratio of 17β(H),21α(H)-moretanes to their corresponding

17α(H),21β(H)-hopanes decreases with increasing thermal maturity from about 0.80 in immature bitumens to values of less than 0.15 in mature source rocks and in oils to a

99 minimum of 0.05. The calculated C30-moretane/C30-hopane ratio of the Bhuban and Boka

Bil shales varies from 0.09 to 0.44 and 0.05 to 0.39, respectively. It matches the range of immature-mature thermal maturity condition. The cross-plot of ol/C30-hoapne versus bc/C30-hopane (Appendix C9) shows the bc/C30-hopane generally decreases with depth whereas ol/C30-hoapne increases with depth. This follows increased maturity of the analyzed samples with depth (e.g., Peters et al., 2005).

The calculated diasterane 20S / (20S + 20R) ratio of the studied shales varies from 0.13 to

0.70 (Bhuban) and 0.17 to 0.80 (Boka Bil). Mackenzie et al. (1980) stated the thermal equilibrium condition of the source rock might reach at the point of 0.60 for diasterane 20S

/ (20S + 20R). The calculated diasterane 20S / (20S + 20R) ratio of the analyzed Bhuban and Boka Bil samples again supports the range of immature to mature thermal condition as interpreted above. Nonetheless, the yellow-orange to orange-brown color corresponding to thermal alteration index (TAI) 2.5-2.8 of the identified spore under microscope (normal white reflected light) represents the immature to early mature oil window condition of the analyzed shale samples. The solid bitumen or bitumen stain is considered as ‘free’ or expelled hydrocarbon. This type of bitumen stain is observed in the analyzed shales under microscope. It also suggests the organic matter of the studied shales has partly expelled hydrocarbons in the related petroleum system of the Bengal Basin, Bangladesh.

4.1.4.2 Hydrocarbon generation potential

The cross-plot of Tmax (°C) and production index (PI) shows that the organic matter of analyzed Bhuban and Boka Bil shale samples have already started to generate hydrocarbons

(Powell, 1978; Farhaduzzaman et al., 2013h and 2013i) (Fig.4.1.11). It is also supported by the earlier interpretation based on vitrinite reflectance, TAI (2.5-2.8) and Tmax values.

100 The measured SRA (or RE) Tmax of the analyzed shale samples varies from 420 to 441 °C

(Bhuban) and 420 to 440 °C (Boka Bil). The hydrocarbon generation usually starts at the maturity level of 435 °C (Peters and Cassa, 1994). The studied Bhuban and Boka Bil shales with low to fair TOC (Bhuban 0.14-1.42%; Boka Bil 0.14-0.57%), low to fair S2 values (Bhuban 0.13-3.76 mg HC/g TOC; Boka Bil 0.16-0.40 mg HC/g TOC), low to moderate total extract (Bhuban 132-2814 ppm; Boka Bil 235-1381 ppm), low to fair production index (Bhuban 0.11-0.40; Boka Bil 0.15-0.30), low to medium hydrocarbon yield (Bhuban 16-139 mg HC/g TOC; Boka Bil 35-282 mg HC/g TOC) and some liptinite macerals suggest poor to fair potential for hydrocarbon generation. The cross-plot of hydrocarbon yield (mg HC/g TOC) and hydrocarbon extract (%) corresponds to marginal to very good hydrocarbon potential of the analyzed Bhuban and Boka Bil shale samples

(Fig.4.1.12). But this interpretation of high quality source potential is not supported by the other evidences. The mean vitrinite reflectance value ranges from 0.48 to 0.71 %Ro in the analyzed Bhuban shales and 0.48-0.70 %Ro in Boka Bil shales (equilibrium value is about

0.60) suggests that the organic matter of the analyzed Bhuban and Boka Bil samples have partly achieved the thermal maturity level for hydrocarbon generation. The dominancy of short chain n-alkanes (C16-C20) in the gas chromatogram (TIC) of both the Bhuban and

Boka Bil Formations indicates the generation of gaseous hydrocarbon with some condensate. The liquid hydrocarbon potential in the analyzed shale samples is most likely due to the presence of liptinitic macerals (Farhaduzzaman et al., 2013j). The triangular diagram based on petrographic analyses (vitrinite-liptinite-inertinite) (Fig.4.1.13) indicates that the organic matter of the analyzed Bhuban and Boka Bil shale samples are suitable for gas generation. In fact, the entire petroleum discovery is natural gas with little amount of condensate and oil in the Bengal Basin, Bangladesh. This is in good agreement with the

101 present interpretation of hydrocarbon generation potential of the Bhuban and Boka Bil

Formations.

Fig.4.1.11. A cross-plot of Tmax (˚C) and production index (PI). Both of the studied Bhuban and Boka Bil shale samples fall within and outside the hydrocarbon generation regime. But Bhuban shows relatively higher maturity (c.f., Powell, 1978).

Fig.4.1.12. A cross-plot of HC yield and hydrocarbon in extract. The studied Bhuban and Boka Bil shale samples correspond mostly to marginal-good quality petroleum source rock potential with marginal to early mature thermogenic condition (e.g., Powell, 1978).

102

Fig.4.1.13. A triangular diagram from visual kerogen analysis (vol %). The analyzed Bhuban and Boka Bil shales represent the generation potential for dry gas (gas-prone) (adopted after Tissot and Welte, 1978).

4.1.4.3 Environment of deposition

The depositional environment of shale and its condition of deposition is often considered as very complex. The modeled steranes triangular plot (Fig.4.1.14) indicates that both of the analyzed Bhuban and Boka Bil shales deposited mostly in terrestrial environmental setting with some marine inputs (Huang and Meinschein, 1979). Diasteranes comparing with regular steranes depend on both lithology and maturity (Peters and Moldowan, 1993). They are, therefore, often used to distinguish carbonate facies (low diasteranes) from clastic facies (Waples and Machihara, 1991). The noticeable presence of diasteranes compared to steranes of the analyzed Bhuban and Boka Bil shale samples characteristically supports the clastic depositional facies.

103

Fig.4.1.14. Relationship between sterane compositions, source input and depositional environment. Both of the analyzed Bhuban and Boka Bil Formation shales are dominated by terrestrial organic matter input. A minor contribution is from marine sources (e.g., Waples and Machihara, 1991).

The cross-plot of Pr/nC17 versus Ph/nC18 (Fig.4.1.15) based on the analyzed samples implies the source of the organic matter of Bhuban and Boka Bil shales is derived mainly from a terrestrial environment. The environment of deposition was an alternation of oxic

(oxidation) to anoxic (reduction) conditions (Peters et al., 2005). The cross-plot of Pr/Ph versus C27/(C27+C29) sterane from the present study (Bhuban and Boka Bil Formations) indicates mostly the terrestrial depositional environment with oxic-anoxic depositional condition (Waseda and Nishita, 1998) (Fig.4.1.16). The marine (pelagic) influence is also suggested by this diagram, in good agreement with the early interpretation above. The presence of cadalene, the diaromatic counterpart of cadinane identified in the analyzed

PyGC pyrograms, represents another terrestrial marker compound. This is consistent with low thermal maturity as observed in the studied Bhuban and Boka Bil samples (Aarssen et al., 1992; Wan Hasiah, 1999a).

104 The presence of bicadinane in the gas chromatograms (m/z 191) of the analyzed Bhuban and Boka Bil samples also supports this terrestrial depositional setting as previously reported by Pearson and Alam (1993).

Fig.4.1.15. A plot of pristane/nC17 versus Phytane/nC18 for the examined samples infer oxicity and organic matter of the source rock depositional environment (e.g., Peters et al., 2005; Koeverden et al., 2011). The analyzed Bhuban and Boka Bil samples support the terrigenous Type III and mixed Type III/II source regions under oxic-anoxic condition.

The oxic condition of any terrestrial depositional environment has extensively been appraised by various authors considering the ratio of Pr/Ph (Brooks et al., 1969; Powell and

McKirdy, 1973; Peters and Moldowan, 1993). They reported that pristane formation occurs in oxidizing environments (e.g., swampy peat bogs) whereas phytane occurs in reducing type environments. The source rocks with Pr/Ph ratio greater than one are more likely to have formed in an oxidizing environmental setting. However, there are some complexities in the mode of their formation.

105

Fig.4.1.16. A cross-plot of Pr/Ph ratios and sterane C27/(C27+C29) values related to deposition environment and source. Both of the analyzed Bhuban and Boka Bil shales suit terrestrial (oxic-anoxic) depositional setting and minor influence from pelagic source (c.f., Waseda and Nishita, 1998; Sawada, 2006; Hossain et al., 2009).

Peters and Moldowan (1993) argued that samples within the oil-generative window having high Pr/Ph ratios >3 indicate terrestrial organic matter under oxic conditions. Therefore, the

Pr/Ph ratios of the analyzed shales, ranging from 0.99 to 3.41 (Bhuban Formation) and 0.58 to 3.65 (Boka Bil Formation), indicate terrestrial environment. And the condition of deposition was oxic. Nevertheless, the dominating C31-homohopane and the large amounts of moretane of the explored Bhuban and Boka Bil shale samples also suggest the terrestrial environments as claimed by Waples and Mashihara (1991) and Peters and Moldowan

(1993).

106 Mello et al. (1988), Barakat et al. (1997) and Huang and Pearson (1999) stated that the

Ts/Tm value below one implies the lacustrine or marine environment and above one marks nonmarine or marine deltaic environment. The calculated Ts/Tm value of the analyzed

Bhuban (0.09-0.87) and Boka Bil (0.12-1.86), however, supports the mixed (nonmarine to marine) depositional environment.

Berner and Raiswell (1984) discussed the source rocks with C/S ratio 0.5-5 represent marine environment while C/S ratio greater than 10 corresponds to nonmarine (fresh water or terrestrial) environment. The measured C/S ratio of the analyzed shale samples ranges from 4.2 to 128.6 (Bhuban Formation) and 2.4 to 53.3 (Boka Bil Formation). This indicates a mixed depositional environment, i.e., mostly terrestrial depositional settings with slight marine influenced sources. Sampei and Matsumoto (2001) used C/N ratio as an indicator for the organic matter found in the source rocks. They stated the C/N ≥15 implies the terrestrial vascular plants. The calculated C/N ratio of the analyzed shale samples varies from 0.6 to 13.3 (Bhuban Formation) and 0.8 to 4.2 (Boka Bil Formation) representing mixed depositional environmental sources (nonmarine to marine) for organic matter. So, in the source rocks containing less than 1% TOC, the inorganic nitrogen has influenced the ratio of C/N. It eventually has decreased the ratio values. This observation agrees with the observation previously reported by Sampei and Matsumoto (2001).

The current observation mentioned above suggests the organic matter derived mostly from terrestrial plants with minor influence from marine sources. The environment of deposition was an alternation of oxic to anoxic conditions. The terrestrial depositional environment is also supported by dominating vitrinite macerals and the high presence of woody fragments.

107 The marine influence is suggested by the presence of liptinite macerals (resinite, cutinite and liptodetrinite) and fluorescent amorphous materials under microscope. Detailed palynological study and isotopic analyses could be recommended for further clarification of its depositional type and geological settings.

4.1.4.4 Stratigraphic correlation

Most of the stratigraphic terms now used to describe the Tertiary successions of the Bengal

Basin (Bangladesh) have been established in comparison to those of Lower or Upper

Assam (India). Evan’s (1932) classification of sediments is based almost only on lithologic characteristics and represents merely a local stratigraphy (Das Gupta, 1977). Because of lack of marker horizons (Khan and Muminullah, 1980), diachronism of formations and due to spatial changes in lithologies (which commonly occur in prograding delta sequences), it is impossible to lithologically correlate certain formations between different parts of a basin or even between two different basins as tried in the Bengal Basin (Bangladesh) in the past

(Das Gupta, 1982; Reimann, 1993). The Tipam Sandstone, for instance, has a Miocene age in the Upper Assam Basin. This deltaic-fluviatile succession has a Pliocene age in the eastern portion of the Surma Trough (a sub-basin of the Bengal Basin), Bangladesh.

Surma Group has been divided into two formations: the lower Bhuban Formation and the upper Boka Bil Formation. Both the Bhuban and Boka Bil Formations show extensive lateral facies change as well as vertical variation in sand to shale ratio from place to place.

This has made it difficult to correlate the units across the basin. Many workers have pointed out the subdivision of monotonous and repetitive sand-shale of Surma Group into Bhuban and Boka Bil Formations is often ambiguous without diagnostic criteria (Johnson and

Alam, 1991; Imam, 2005).

108 Alam et al. (2003) reported the contact between the Bhuban and Boka Bil Formations or the internal units of these formations is difficult to recognize based on the Evan’s (1932) scheme of lithostratigraphic correlation.

The findings of the current study from the geochemical and petrographical methods (e.g., organic matter quantity, quality and maturity, hydrocarbon generation potential, hydrocarbon yield, maceral analysis, elemental analysis and depositional environment) show there is no major difference between the studied shales of Bhuban and Boka Bil

Formations, the Bengal Basin, Bangladesh (Farhaduzzaman et al., 2012b). For example, both Bhuban and Boka Bil shales correspond to similar properties which are shown in

Appendix C10.

109

4.2 PETROLEUM SOURCE ROCK- PERMIAN COALS

4.2.1 Macroscopic Study of Coals

4.2.2 Microscopic Study of Coals

4.2.3 Organic Geochemical Study of Coals and Associated Sediments

110 Chapter 4.2.1 Macroscopic Study of Coals

A total of 27 coal samples are used for proximate and elemental analyses. Eleven samples form Barapukuria Coal Basin and 11 samples from Dighipara Coal Basin are used for the present purpose. An additional five bulk coal samples (collected from a stockpile of coal mine) are also analyzed for comparative assessment with the results obtained from core samples.

4.2.1.1 Coal seam characteristics

Six seams (Seam I, Seam II, Seam III, Seam IV, Seam V and Seam VI) are identified in the

Barapukuria Basin (Armstrong, 1991). Seam VI is the thickest seam (average 36m) and apart from some thin impersistent bands of coal below, it is the basal coal seam in this

Gondwana basin. It contains bulk of the Barapukuria coal resource (>90%). On the other hand, three seams (Seam A, Seam B and Seam C) are recognized in Dighipara Basin. The maximum cumulative coal thickness encountered in the Dighipara is 71m (Hasan and

Islam, 2003). There is a close similarity of these coals with the Permian coals of Australia,

South Africa and India (Armstrong, 1991; Akhtar, 2001; Farhaduzzaman et al., 2008). The sulfur content (%) of the coals from both of these Barapukuria and Dighipara basins is low.

According to JMG results, it is 0.61% for Barapukuria coals and 0.66% for Dighipara coals. The calculated gross calorific value (GCV) is 5466-7032 (mean 6313) kcal/kg and

4815-7303 (mean 6382) kcal/kg for Barapukuria and Dighipara coals respectively.

The coals of Barapukuria and Dighipara are mainly banded dull to dull in nature as stated by the JORC Code (2004). The coals of Dighipara, on the other hand, show higher amounts of bright bands than those of Barapukuria. Banded bright and bright banded coals are not uncommon in the studied coal seams of the Barapukuria and Dighipara. The coal is highly

111 cleated. The cleats are generally irregular to planar and pyritic infill is common along the joint planes and cleats. Few photographs of the studied coals are shown in Fig.4.2.1.1.

4.2.1.2 Proximate analysis

The proximate analysis of coal can be reported on the basis of four ways as mentioned below (World Coal Institute, 2007):

 As received (ar)- includes total moisture (TM).

 Air dried (ad)- includes inherent moisture (IM) only.

 Dry basis (db)- excludes all moisture.

 Dry ash free (daf)- excludes all moisture and ash.

Fig.4.2.1.1. Photographs of coal samples collected from the Barapukuria and Dighipara basins. (A) and (B) are the bulk samples of Barapukuria Basin whereby (C) and (D) are the core samples of Dighipara Basin. The samples show different bands of coal, e.g., dull band (db) and bright parting (bp) along with a joint (j) in photograph D. This is a characteristic feature of a bituminous coal.

112

The proximate analysis is carried out on air dried (ad) basis for the currently investigated coal samples. The results of proximate analysis (ad basis) including sulfur content (%) and gross calorific value (GCV, kcal/kg) of coals from the Barapukuria and Dighipara basins

113 are displayed in Table 4.2.1.1. Here the data taken from two laboratories such as University

Malaya Geology Laboratory (denoted by TGA) and Minerals and Geoscience Department

Malaysia (denoted by JMG) are compared. It finds a good similarity between these two results which has increased the confidence level of the data usage. The moisture, volatile matter, fixed carbon and ash are measured: 3-5%, 23-32%, 48-59% and 5-22% respectively for coal core samples of the Barapukuria Basin. These values are 2-6%, 26-32%, 45-62% and 4-26%, respectively for coal core samples of the Dighipara Basin. Bulk coal samples are also analyzed for comparative assessment with the core samples of the Barapukuria

Basin. The values of moisture, volatile matter, fixed carbon and ash of the Barapukuria bulk samples are 2-3%, 29-34%, 50-60% and 5-16%, respectively. The arithmetic mean of carbon, hydrogen, nitrogen, sulfur and oxygen are defined (dry ash free- daf basis) 83%,

5.1%, 1.7%, 0.77% and 9.4%, respectively for Barapukuria (Armstrong, 1991).

The ash analysis (elemental concentration as oxides) of the Barapukuria coals has already been carried out by Armstrong (1991). But there is no work published on Dighipara coals and accordingly the elemental concentration (ppm, ad basis) of Dighipara coals has been measured (Table 4.2.1.2).

4.2.1.3 Discussion

The random mean vitrinite reflectance (%VRr) of Barapukuria coal ranges from 0.72 to

0.78% while it ranges from 0.70 to 0.80% for Dighipara coals (details in chapter 4.2.3).

Proximate analysis is one of the most important tools to investigate the geochemical properties of coal (World Coal Institute, 2007; Belkin et al., 2009). It can be used to establish the rank of coals and it provides the basis for buying and selling (ASTM D 3172-

89).

114

115

Fig.4.2.1.2. The elemental concentration of the analyzed coal samples from the Dighipara Basin. Mostly all of the identified elements cross their Clarke values which point to the environmental hazards during combustion.

4.2.1.3.1 Moisture contents

Moisture is an important property of coal since all coals are mined wet. Groundwater and other extraneous moisture is known as adventitious moisture and is readily evaporated.

Moisture held within the coal itself is known as inherent moisture (IM) and is analyzed quantitatively. According to results of TGA and JMG laboratories, the measured IM is low

(2-6%).

116 4.2.1.3.2 Volatile matter

Volatile matter in coal refers to the components of coal (except for moisture) which are liberated at high temperature in the absence of air. This is usually a mixture of short and long chain hydrocarbons, aromatic hydrocarbons and some sulfur. The volatile matter is fairly high in both of the investigated basin coals. Measured volatile matter and ash content of Barapukuria coals are 28% and 14% (mean) while these are 29% and 12% (mean) for

Dighipara coals (air dried basis; TGA laboratory). These mean values are 29% and 15% for

Barapukuria and 28% and 15% for Dighipara coals following JMG laboratory respectively.

These parameters are frequently used to classify the coal ranks and types (Stach et al.,

1982; Singh and Singh, 1996). The coals of both basins are of similar high volatile bituminous B rank.

4.2.1.3.3 Ash yield

Ash content of coal is the non-combustible residue left after coal is burnt. It represents the bulk mineral matter after carbon, oxygen, sulfur and water are driven off during combustion. The ash content is low (4-26% TGA laboratory; 6-29% JMG laboratory) in the currently analyzed coal samples from both basins.

4.2.1.3.4 Fixed carbon

The fixed carbon content of the coal is the carbon found in the material which is left after volatile materials are driven off. This differs from the ultimate carbon content of the coal because some carbon is lost in hydrocarbons with the volatiles. Fixed carbon is used as an estimate of the amount of coke that will be yielded from a sample of coal. The high content of fixed carbon (48-60% TGA laboratory; 45-61% JMG laboratory) in the presently

117 analyzed coals indicates that these coals can partly be used to produce coke. This byproduct

(coke) is an important fuel for the steel industries.

4.2.1.3.5 Elemental concentrations

A compositional analysis including major, minor and trace elements of coal is useful in the overall description of the coal quality (Finkelman, 1999). It is used to predict behavior of ashes and slags in combustion chamber (ASTM D 3682-87). The concentration of elements measured is correlated with coal Clarke values as well as themselves. ‘Clarke’ is the average content of a given chemical element in the Earth’s crust and also in the hydrosphere (Ketris and Yudovich, 2009). Almost all of the identified elements exceed the coal Clarke values in the analyzed coal samples (Table 4.2.1.2 and Fig.4.2.1.2A-F). The toxicity of elements in coal and coal ashes and their environmental significance have been evaluated extensively by various authors (e.g., Swaine, 1990; Spears and Zheng, 1999;

Goodarzi, 2002; Finkelman et al., 2002; Finkelman, 2004; Ren et al., 2004; Jorjani et al.,

2008; Sia and Wan Hasiah, 2011; Dai et al., 2012). In general, the elements in coal can be divided into two broad groups namely (a) elements of prime environmental concern and (b) elements that could be of environmental interest (Swaine, 1990; Goodarzi, 2002). The first group includes Cr, Cd, Ni, Pb, As, F and Hg. The later includes Co, Cu, Zn, Mn, B, Be, Cl,

Mp, Sb, Sn, Th, Ti, U and V.

The chromium (Cr) in the studied samples is fairly high (mean 42ppm) compared to the coal Clarke value (17±1ppm) (Fig.4.2.1.2A). Based on China coals, Ren et al (2004) stated that high concentration Cr could be one of the important causes of lung cancer. So it is one of the potentially hazardous elements in the studied coals. Mixed layer clay minerals, pyrite and hematite are considered as the host for Cr (Goodarzi, 2002). The nickel (Ni) content

118 (mean 38ppm) of the analyzed samples is high compared to the Clarke value (17±2ppm)

(Fig.4.2.1.2A). Its origin is not well established (Swaine, 1990), but is thought to be occurred in millerite (Ni) and organic matter. Asthma, central nervous system effects, gastrointestinal effects, headache, neoplasia of lung and respiratory tract are some common health effects attributed to nickel exposure (Gupta, 1999).

Lead (Pb) is considered as both potentially hazardous element and regulated constituent as solid waste (Resources Conservation and Recovery Act RCRA, 1976). Chronic Pb poisoning often begins with vague symptoms in human health such as anorexia, muscle discomfort, malaise and headache as well as gastrointestinal effects (Gupta, 1999;

Finkelman, 2004). The occurrence of Pb is most commonly associated with the minerals galena (PbS) (Swaine, 1990; Dai et al., 2006) and less commonly with clausthalite (PbSe) and crocoite (PbCrO4) (Hower and Robertson, 2003; Sia and Wan Hasiah, 2011). Most of the samples showed low Pb concentration (mean 7ppm) (Fig.4.2.1.2B). Few samples show higher than the Clarke value (9±0.7ppm) and it could be a concern for environmental consideration. The copper (Cu) content (mean 24ppm) is much higher than the Clarke value

(16±1ppm) (Fig.4.2.1.2B). It occurs in sulfur bearing minerals (e.g., chalcopyrite) and other clays and carbonates (Goodarzi, 2002). Gastrointestinal disorder is the main effect caused by high contents of copper (Gupta, 1999). It could be a hazardous element in the studied area during coal combustion.

The magnesium (Mg) concentration (mean 118ppm) of the analyzed coal is not too high falling below the world average (200ppm) (Fig.4.2.1.2C). It is related with clay minerals as well as the carbonates (Finkelman, 1994; Sia and Wan Hasiah, 2011). But hence it is consistent with association of clay minerals instead with carbonates.

119

To date there is no reported deleterious health or environmental impacts from zinc (Zn) emissions while utilizing the coal in coal-fired power plants (Swaine, 1990). The enrichment of Zn in coals is mostly related with the mineral sphalerite. Albeit mostly all of the samples show higher concentration than the Clarke value but hence the Zn is not a hazardous element (Fig.4.2.1.2C).

The cadmium (Cd) concentration is much higher (mean 2.69ppm) compared to the Clarke value (0.2±0.04) (Fig.4.2.1.2D). Cd occurs mostly as solid solution in sphalerite and pyrite.

It also occurs in association with clays, carbonates and organic matter (Goodarzi, 2002; Dai et al., 2012). It is an extremely toxic element while exposed to the nature (HSE, 2003).

Excessive amounts of Cd might cause many problems for kidney disease as well as fever, chest pain and eye-nose infections (Finkelman, 2004). Therefore, Cd is a potential hazardous element for the environmental concern during combustion of the analyzed coals.

The strontium (Sr) concentration is lower than the Clarke value (Fig.4.2.1.2E) and it is not an environmental issue here.

The potassium (K) concentration of Dighipara coal is high (mean 556ppm) compared to the world average value (100ppm) (Fig.4.2.1.2F). The high concentration is possibly because of the enrichment of the mixed layer clays (Spears and Zheng, 1999; Sia and Wan Hasiah,

2011). It is not an environmental concern. The iron (Fe) concentration measured is very low

(mean 1852ppm) compared to the world average (10000ppm) (Fig.4.2.1.2F). It can be combined inorganically (e.g., pyrite, marcasite, siderite and ankerite) or organically in coals. Microscopic observation showed that the Fe is associated with both syngenetic

(Fig.4.2.1.3A) and epigenetic pyrites (Fig.4.2.1.3B). The presence of these kinds of pyrite

120 most frequently causes acid rain utilizing the coals (Hower and Bland, 1989). It is harmful for the environment, especially for the crops. The higher presence of Fe sometimes forms numerous pyrites (in association with sulfur) which would ultimately be a hazard for environments.

Fig.4.2.1.3. Photomicrograph shows iron and sulfur bearing mineral pyrite which is of syngenetic (spy, A) or epigenetic (epy, B) origin. It is associated with vitrinite macerals observed under microscope with normal reflected white light under oil immersion.

The cobalt (Co) concentration in the analyzed coal samples is much higher (mean 17ppm) than the Clarke value (6±0.2). Sulfide minerals or fine grained accessory sulfide in clays and organic matter in coal are the major source of cobalt (Goodarzi, 2002). Studies suggest that ingestion of an excessive amount of cobalt causes polycythemia and intercellular hypoxia. Chronic exposure to cobalt at higher concentrations produces goiter (Krishnan,

1995; Gupta 1999). Therefore, it is a hazardous element in the studied coals.

121 Chapter 4.2.2 Microscopic Study of Coals

The present study deals with two Permian coal deposits of the Barapukuria and Dighipara coal basins. These coal bearing basins are situated within the Rangpur Saddle area of

Platform unit of the Bengal Basin, Northwest Bangladesh. The Gondwana Group contains the valuable coal in the Barapukuria and Dighipara coal basins. A total of 27 coal samples were analyzed for the current investigation. Among the total samples, 22 samples are collected from the cores and five samples from a stockpile of bulk coal dumped at the

Barapukuria Coal Mine.

4.2.2.1 Macerals

The quantitative and qualitative analyses of macerals and associated minerals (vol.%) were carried out in the present study. The details of different macerals and mineral matter are summarized in Tables 4.2.2.1 and 4.2.2.2 and Appendix D1. The analyzed coal is rich in inertinite group macerals followed by vitrinite and liptinite group. Semifusinite, fusinite and inertodetrinite are the main constituents of the inertinite group. Collotelinite and collodetrinite are the dominant components of vitrinite group. Sporinite, cutinite and resinite are common macerals of the liptinite group.

4.2.2.1.1 Vitrinite group: All the macerals of vitrinite group (ICCP System 1994 (1998)) are observed in the analyzed coal samples. Of this maceral group (mean 31%, in total three sets of samples), telovitrinite (telinite-1% and collotelinite-18%) is the most dominant subgroup, followed by detrovitrinite (collodetrinite-9% and vitrodetrinite-2%) and gelovitrinite (gelinite-1% and corpogelinite-1%).

122 Telinite: Although telinite is rare, some large bands (100-300 µm width) are observed in the analyzed coal samples. The cell cavities and lumens are partially or completely filled with argillaceous mineral matters and other macerals such as corpogelinite, resinite, micrinite, clay minerals and carbonates. Telinite is characterized by its clear cellular structure and grey color in reflected white light (Photomicrograph 4.2.2.1A).

123 Collotelinite: Collotelinite is the most dominant maceral of the vitrinite group. It is characterized by a more or less homogeneous structureless appearance, which is most commonly found in the vitrain lithotype and, less commonly, in clarain. It is sometimes observed as a cement or impregnating material for the other associated macerals. A folded nature is also observed within this maceral. The color varies from light grey to moderately dark grey in reflected white light and occurs as both thick and thin bands (Photomicrograph

4.2.2.1B).

124

Vitrodetrinite: Vitrodetrinites are observed as isolated and small (less than 10µm) fragments of different shapes, surrounded by other non-vitrinitic macerals. Vitrodetrinite occurs more frequently in microlithotype vitrinertite and, less commonly, in durite

(Photomicrograph 4.2.2.1C).

Collodetrinite: Collodetrinite is characterized by its mottled and amorphous vitrinitic groundmass that binds other different macerals and components. It is found in a small

125 number of places as material intruded within other macerals. It shows comparatively low reflectance. When observed parallel to bedding, it forms irregular patches

(Photomicrograph 4.2.2.1D and 1E). The fluorescence nature of vitrinite is also observed in collodetrinite and collotelinite. It shows a dull yellow to yellowish brown fluorescence in ultraviolet light or reddish yellow when associated with sporinite groundmass.

Collodetrinite is commonly found in clarite and, less commonly, in durite and vitrinertite.

Gelinite: Gelinite is rare in the analyzed coal samples. It is observed as structureless infillings in the cracks and other voids of the semifusinites and fusinites (Photomicrograph

4.2.2.1E) and is, therefore, likely to be of secondary origin.

126 Corpogelinite: Corpogelinite has been found forming homogenous and discrete bodies of cell infillings, mainly incorporated in telocollinites. It is similar in color and reflectance to the surrounding telocollinite, but has a high relief (Photomicrograph 4.2.2.1F). It is not common in the analyzed samples.

4.2.2.1.2 Liptinite group

In the analyzed coal samples, the macerals of liptinite group are identified by their comparative darker color in reflected white light and different fluorescence nature in ultraviolet light. The structured liptinite macerals observed in the studied Permian coals are sporinite, cutinite, resinite and liptodetrinite while the unstructured liptinites include bituminite, fluorinite and exsudatinite. The most dominant sub-macerals of this group

(mean 22%, in total three sets of samples) are sporinite (14%) and cutinite (4%), followed by resinite (1%), bituminite (1%), fluorinite (1%), liptodetrinite (1%) and exsudatinite

(1%).

Sporinite: Sporinite is the most dominant maceral of the liptinite group. It occurs as elongated, flattened or disc-shaped, thread-like bodies that are parallel to the stratification.

Both microsporinite (tenui and crassi) and megasporinite (tenui and crassi) have been found in the studied samples (Photomicrograph 4.2.2.2A and 2B). The interior of the spore is often recognized. Under white light, they appear darker (dark grey to brownish black) than the surrounding telocollinite, while under ultraviolet light they show reddish yellow to orange colors of moderate intensity. The megaspore is comparatively lower in concentration than the microspore. A sporangium consisting of numerous microspores has also been observed (Photomicrograph 4.2.2.2C). Some sporangia show a well-organized form whereas some do not have a definite form.

127 A particular colony of microspores has been identified in the studied samples

(Photomicrograph 4.2.2.3A). Sporinite is common in microlithotypes of clarite and durite.

Cutinite: Cutinite is found as thin cylindrical bodies with serrated margins or a crenulated form. Megacutinite is common in these coals. Both tenui (thin-walled) and crassi (thick- walled) varieties are found. Cutinite is dark grey to black in color in reflected white light but shows a yellowish-orange to light brownish red color under ultraviolet light

(Photomicrograph 4.2.2.3B and 3C). It is common in clarite bands.

Resinite: Resinite appears as a rounded, oval or spherical-shaped body and occurs as cell

(cavity) fillings or isolated rounded to subrounded rod-like body. Clusters of resinite bodies have also been observed in the investigated coal samples (Photomicrograph 4.2.2.4A).

They are dark grey to brown under reflected white light. In fluorescent light they show a wide range of color, mostly greenish-yellow to yellow, occasionally becoming orange and light brown in color. Resinite is frequently found in the microlithotype of clarite and, less commonly, in durite bands.

Liptodetrinite: Liptodetrinite embraces the fragmental parts and detrital remains of structured liptinite macerals produced due to degradation and crushing (Photomicrograph

4.2.2.4B).

128

Photomicrograph 4.2.2.1. (A) Cell structure is clearly visible in moderate grey telinite (te). (B) Structureless collotelinite (ct). (C) Discrete small isolated vitrodetrinite (vd) is also observed in the analyzed samples. (D) Collodetrinite (cd) as vitrinitic ground mass binding other macerals (e.g., semifusinite-sf, inertodetrinite-id, liptodetrinite-ld and sporinite-sp). (E) Gelinite (gl) is found as cell fillings of semifusinite. (F) Corpogelinite (cg) is investigated as cell fillings of telinite [All photomicrographs are shown in normal reflected white light].

129

Photomicrograph 4.2.2.2. (A) Elongated to disc shaped micro-sporinite (sp). (B) Mega- sporinite; Both types show dark grey to brownish black color in reflected white light (A1 and B1). They fluoresce reddish-yellow to orange (A2 and B2) under ultraviolet light. Both thin-walled and thick-walled types are also identifiable. (C) Sporangium consisting of numerous microspores is frequently observed in the samples (C1 under reflected white light and C2 under ultraviolet light).

130

Photomicrograph 4.2.2.3. (A) Colony of microspores is observed whereby A1 shows under reflected white light and A2 shows under ultraviolet light. (B1) and (C1) Narrow banded to cylindrical micro-cutinite and mega-cutinite (cu) with serrated margins are dark grey to black in normal reflected white light. (B2) and (C2) Cutinite shows yellowish orange to light brownish red fluorescence under ultraviolet light. Both thin-walled (B) and thick- walled (B and C) cutinite are observed in the studied samples.

131

Photomicrograph 4.2.2.4. (A) Rounded to subrounded and oval shaped isolated and colonial resinite (re) dark grey to dark brown in reflected white light (A1). They show greenish-yellow to yellow fluorescence under ultraviolet light (A2). Lamellar formed bituminite (bt) shows dark brown color in reflected white light (A1). It fluoresces yellowish- brown under ultraviolet light. (B) Liptodetrinite (ld) is found as fragmental part of liptinite. B1 shows under reflected white light and B2 shows under ultraviolet light. Fluorinite (fl) is dark grey to dark brown in reflected white light (B1) while it shows brilliant yellow fluorescence occurred as oil droplets in ultraviolet light (B2). (C) Exsudatinite (ex), as cracks or empty cell filling secondary maceral, show dark brown color in reflected white light (C1). It fluoresces yellow to orange in ultraviolet light (C2). Lamellar bituminite (bt) is also observed here.

132

Photomicrograph 4.2.2.5. (A) White color degradofusinite (dfs) with poorly preserved cell structure in normal reflected white light and fusinite does not show any fluorescence under ultraviolet light. (B) White color pyrofusinite (pfs) with well-preserved cell structures contacted with degradofusinite. (C) Degradosemifusinite (dsf) and pyrosemifusinite (psf) show relatively lower reflectance than fusinite in normal reflected white light. (D) Inertodetrinite (id) is found as isolated fragment of fusinite; whitish color very fine grained aggregates (without any particular shape) are identified as micrinites. (E) Structureless macrinite (ma). (F) Oval shaped and rimmed with notches secretinite (sc) is observed in the samples [all photomicrographs are shown in normal reflected white light].

133 Fluorinite: Teichmüller (1974a) and Cook et al. (1981) have shown that fluorinite is formed from the oils and fats of higher plants. Teichmüller (1974a) differentiated fluorinite from resinite on the basis of its brilliant yellow fluorescence under ultraviolet light. In the studied coals, fluorinite occurs as cell fillings, and also as veins and lenses or oil droplets, which are characterized by a brilliant yellow color and very high intensity under ultraviolet light and dark brown color in reflected white light (Photomicrograph 4.2.2.4B).

Bituminite: Bituminite occurs as groundmass and lamellar forms (Singh and Singh, 1994).

It may also be present as a solid bitumen. Bituminite commonly shows yellow to orange fluorescence (Photomicrograph 4.2.2.4C) and may at times show a brown fluorescence.

Teichmüller (1974a and 1974b) and Singh and Singh (2004) demonstrate that bituminite is an amorphous liptinite maceral without a definite shape and that it occurs as finely dispersed lenses, streaks and, in places, as the groundmass of other liptinite macerals.

Bituminite is considered to be a secondary maceral and therefore might be a secondary product derived from resinite and cutinite, with which it is more commonly associated in the studied coal samples.

Exsudatinite: Exsudatinite was first described by Teichmüller (1974b and 1974c). Its occurrence marks the first step in bituminization. It is genetically characterized as being an expelled hydrocarbon liberated from the lipid constituents of liptinites and perhydrous vitrinites or huminites. It occupies void ducts such as cracks, the empty cell lumens of fusinite and secretinite and bedding plane joints. In the studied coals, exsudatinite occurs as veins and has yellow to orange and red-brown colors with moderate to weak intensity under ultraviolet light (Photomicrograph 4.2.2.4C).

134 4.2.2.1.3 Inertinite group

Inertinite group macerals (mean 40%, in total three sets of samples) dominates both the

Barapukuria and Dighipara coals when compared with the other maceral groups, vitrinite and liptinite. This group is characterized by its distinct higher reflectance in white light and absence of fluorescence in ultraviolet light when compared to the vitrinite and/or liptinite also associated with these coals. The macerals identified (ICCP System 1994 (2001)) are semifusinite, fusinite, inertodetrinite, micrinite, macrinite, secretinite and funginite.

Semifusinite (21%), fusinite (9%) and inertodetrinite (6%) are the most common maceral subgroup of the macerals in this group, followed by micrinite, macrinite, secretinite and funginite.

Fusinite: The fusinite has a well-preserved cellular structure. The cell lumens are either empty or are filled mostly with mineral matter and, less commonly, with gelinite. They show a white to yellowish white color under reflected white light, with a very high relief.

They show no fluorescence under UV light. Both degradofusinite and pyrofusinite are present but degradofusinite is more common (Photomicrograph 5A and 5B). Pyrofusinite shows a well-preserved cellular structure, a yellowish-white color and reflectance that is higher than that of degradofusinite, while degradofusinite is characterized by moderately well-preserved cellular structures with a white color and high reflectance. A ‘Bogen

Structure’ is commonly observed in both types (Photomicrograph 4.2.2.5B). The folding nature of fusinite can also be observed in a few places. Sharp contacts have been observed between pyrofusinite and semifusinite, pyrofusinite and collotelinite, and pyrofusinite and degradofusinite. Fusinite is commonly found in microlithotype fusite and inertite, and less commonly, in durite.

135 Semifusinite: The most dominant maceral in the studied coal samples is semifusinite. It is identified by its reflectance, which is intermediate between the vitrinite and fusinite of the same coal sample. The cell cavities (lumens) are partially visible and smaller in size compared to those of fusinite. These cavities are found as being either empty or filled with other constituents, such as clay and resinite. Both pyro and degrade-semifusinite have been observed, but degradofusinite is the more dominant (Photomicrograph 4.2.2.5C). It is found mainly in microlithotype inertite (semifusite), followed by durite and clarodurite.

Inertodetrinite: Inertodetrinite can be identified as discrete small (<10µm) inertinite fragments in the studied samples. It is observed in high concentrations, which appear to have derived from fusinite and semifusinite macerals, and shows a white to yellowish-white color in reflected white light (Photomicrograph 4.2.2.5D). It is mostly observed in vitrinertite and durite bands.

Micrinite: Micrinite occurs as very fine (<2µm) rounded grains which are white to yellowish-grey in color in reflected white light (Photomicrograph 4.2.2.5D). Aggregates of micrinite with an indefinite outline are differentiated from macrinite by their granularity. It is common in microlithotype vitrite and is also found in both vitrinertite and durite. It is considered mainly to be the secondary relics of oil generation (Teichmüller, 1974c; Wan

Hasiah, 2003).

Macrinite: Macrinite is found as an amorphous matrix (groundmass) or as discrete bodies showing no structure. The size ranges from 10 to 40 µm, commonly displaying an elongated shape, and it has a white to pale grey color in reflected white light. It is commonly found in durite (Photomicrograph 4.2.2.5E).

136 Secretinite: Secretinite is occasionally observed in the analyzed samples. It occurs as rounded to oval-shaped perforated bodies without any particular structure

(Photomicrograph 4.2.2.5F). In a few cases, they show an oxidized rim of lower or higher reflectance and internal notches.

Funginite: Funginite is formed of single or multi-celled fungal spores, sclerotia, hyphae and mycelia (stromata, mycorrhiza), and other fungal remains. It is found very rarely in the analyzed coal samples.

4.2.2.1.4 Mineral matter

The mineral components are identified by their black appearance under reflected white light without any relief (with exception of quartz). A considerable amount of mineral matter (7 vol.%) is measured in the analyzed coal samples of both Barapukuria and Dighipara. Clay minerals (6%) are the dominant group with only minor amounts of carbonate, quartz and sulfide (pyrite). The minerals are mostly found as cell/cavity fillings of vitrinite, liptinite and inertinite bands (Photomicrograph 4.2.2.6A and 6B). Pyrite shows golden yellow color in reflected white light with distinct relief and these are identified both as framboids and cavity fillings (Photomicrograph 4.2.2.6C). Carbonate minerals are found as re-precipitated small irregular bodies or patches which show medium grey color in reflected white light with slight relief against vitrinite.

4.2.2.2 Microlithotypes

All the different microlithotypes in the analyzed coal samples are identified: Tables 4.2.2.3 and 4.2.2.4 and Appendix D2 show the concentration details. Trimaceral group members such as clarodurite (22%) and duroclarite (21%) (Photomicrograph 4.2.2.7A and 7B) are

137 found to be the most dominant maceral associations in the studied samples. Durite (9%) is the most dominant bimaceral group: durite I (Photomicrograph 4.2.2.7C) is present in higher amounts than durite E. Other bimaceral groups i.e., clarite (Photomicrograph

4.2.2.8A) and vitrinertite (Photomicrograph 4.2.2.8B) are also common in the samples.

Photomicrograph 4.2.2.6. (A) Cell filling clay minerals (cl) show black color under reflected white light (A1). They don’t show any fluorescence under UV light (A2). (B) Cavity filling clay minerals are black under white light (B1) and show no fluorescence (B2). (C) Cavity filling sulfide minerals, e.g., pyrite (py) occurs as golden yellow color under white light (C1). It does not show any fluorescence under ultraviolet light (C2).

138

Photomicrograph 4.2.2.7. (A) The most dominantly observed trimaceral microlithotype is clarodurite- an association of inertinite (fs, mi), liptinite (cu, sp) and vitrinite (ct) macerals. (B) Another most commonly found trimaceral microlithotype is duroclarite- an association of vitrinite, liptinite and inertinite macerals. (C) Bimaceral microlithotype durite I which includes the inertinite and liptinite macerals with the dominancy of inertinite [Left photomicrographs A1, B1 and C1 are showed under reflected white light whereby the right ones A2, B2 and C2 are shown under ultraviolet light].

139

Photomicrograph 4.2.2.8. (A) Clarite is a bimaceral microlithotype including vitrinite (ct, cd) and liptinite (sp, cu) macerals. (B) Another bimaceral microlithotype is vitrinertite consisting of vitrinite and inertinite macerals. (C) Monomaceral microlithotypes semifusite. (D) Vitrite. (E) Fusite [Here only the photomicrography A2 is shown in ultraviolet light; all rest photomicrographs are taken under normal reflected white light].

140 Semifusite (6%) and vitrite (6%) are identified as the most common microlithotypes of the monomaceral group (Photomicrograph 4.2.2.8C and 8D). On the other hand, of the carbominerites, carbargillite (7%) is much more dominant than carbankerite (1%) and carbopyrite (1%).

Fig.4.2.2.1. A triangular diagram illustrating peat-forming depositional environments based on maceral compositions. The studied samples represent forest swamp, mildly oxic to anoxic conditions, with good tissue preservation (adopted by Mukhopadhyay, 1986).

4.2.2.3 Discussion

4.2.2.3.1 Coal facies models

A number of facies models are in use based on maceral concentrations, maceral indices and maceral associations of the Permian coals studied in different parts of the world. Based on some of the more popular facies models, an initiative has been put in place to reconstruct the paleofacies and depositional conditions of the Permian coals of Bangladesh.

141 4.2.2.3.1.1 Mukhopadhyay (1986) facies model: This model uses macerals interpreting the depositional facies. The Permian Gondwana coals of the Barapukuria and Dighipara

Basins are plotted and analyzed using this model (Fig.4.2.2.1), which indicates that these coals have originated from forest swamps under mildly oxic to anoxic conditions with good tissue preservation.

4.2.2.3.1.2 Singh and Singh (1996) facies model: Since the clastic mineral matter is directly related to water cover in the basin, due importance has been given to the mineral matter content; therefore both the macerals and mineral matter have been used in this facies model. The results for all of the coal samples studied (Fig.4.2.2.2) indicate that there were situations of alternation of oxic and anoxic moor conditions in the basin. This is attributed to fluctuating water cover in the basin.

4.2.2.3.1.3 Diessel (1986) facies model: The coal facies and condition of deposition is analyzed using a cross-plot according to Diessel (1986), based on two parameters, the

Gelification Index (GI) and Tissue Preservation Index (TPI). The formulae of these two parameters are:

The plots (Fig.4.2.2.3) suggest a high tree density in the terrestrial origin of these investigated coal samples, corresponding to a depositional environment of dry forest to piedmont plain conditions.

142 High values of both GI and TPI represent the wet conditions of peat development while low

GI and TPI values correspond to dry conditions (Diessel, 1986). In the present study, the moderately high TPI and the considerable quantity of mineral matters are the indicators of intermittently dry forest swamps. The TPI values range from 1.0 to 4.3, suggesting a lateral increase in the rate of subsidence and depth of the basin.

Fig.4.2.2.2. Environmental depositional conditions of the coals based on the composition of the macerals and mineral matter contents. The explored samples fall within an alternation of oxic-anoxic moor (c.f., Singh and Singh, 1996).

4.2.2.3.1.4 Calder et al. (1991) facies model: Water cover is an important condition for the deposition of the peat and coal in the swamp. In consideration of this, the Ground Water

Index (GWI) and Vegetation Index (VI) have been calculated to identify the major peat mire paleoenvironments, that is, bog forest and swamp forest, together with the

143 hydrogeological conditions that would explain the ombotrophic, mesotrophic and rheotrophic mires. The following formulae are used for the current indices.

Fig.4.2.2.3. A cross-plot of the Gelification Index (GI) and Tissue Preservation Index (TPI) showing the depositional settings of the peat mires. The analyzed samples fall mostly within terrestrial dry forest swamp and piedmont plain (e.g., Diessel, 1986).

The low values of GWI (0.1 - 2.2) and moderate values of VI (1.2 - 4.2) indicate that the coals evolved under ombotrophic (incorporating very low nutrient levels for plant development) to mesotrophic (incorporating moderate nutrient levels for plant

144 development) hydrogeological conditions, containing herbaceous plants (Fig.4.2.2.4). It further supports the contention showed of the model of Singh and Singh (1996) that the water level frequently fluctuated (with a gradual lowering or raising) during the evolutional history of the peat of these Permian coal basins. This interpretation is also in agreement with the terrestrial dry forest to piedmont plain depositional condition (i.e., oxic-anoxic) suggested by the GI-TPI plot.

Fig.4.2.2.4 A cross-plot of the Ground Water Index (GWI) and Vegetation Index (VI) showing the palaeoenvironments of the coal mires. The studied samples also imply mostly bog forest environment and swamp forest (adopted by Calder et al., 1991).

4.2.2.3.1.5 Hacquebard and Donaldson (1969) facies model: The depth of water not only controls the various environments of the vegetation and the deposition of the peat mires,

145 but also affects the mode of preservation of the petrographic entities (Singh and Shukla,

2004). On this basis, Hacquebard and Donaldson (1969) constructed a double triangular facies diagram (later modified by Marchioni, 1980) using the microlithotypes (maceral associations) to interpret the coal facies and depositional conditions. The analyzed coal samples are plotted into this modified double triangle. The upper triangle represents relatively dry conditions (i.e., terrestrial and telmatic) and coals with lower than 20% of dull bands, while the lower triangle corresponds to subaquatic conditions (i.e., limnic and limno-telmatic) and coals with higher than 20% of dull bands. Since the analyzed Permian coals contain more than 20% of dull bands, they have essentially been in the lower triangle.

The related four elements of the facies model are:

A = Sporoclarite+Duroclarite+Vitrinertoliptite

B = Fusitoclarite+Vitrinertite I+Fusite

C = Vitrite+Cuticoclarite+Vitrinertite V

D = Clarodurite+Durite+Macroite+Carbominerite

The plots in this facies model for the investigated coal samples suggest that the coals have evolved mostly in limno-telmatic zones containing floral assemblages associated with reed moor and with intermittent floods leading to the development of a forest moor facies

(Fig.4.2.2.5). Hunt and Smyth (1989) have demonstrated that reed moor (swamps) are often associated with rising water tables (i.e., flooding), which is supported by the present interpretation based on the reconstructed models. However Teichmüller and Teichmüller

(1982) and Singh and Shukla (2004) consider it can be difficult to separate telmatic

(terrestrial) and limnic (subaquatic) facies in swamps due to the frequent of subaquatic sedimentation in the basin.

146

Fig.4.2.2.5. A double triangular diagram based on microlithotypes, illustrating the coal facies. The examined samples indicate a facies range from reed moor to forest moor (adopted by Hacquebard and Donaldson, 1969; Cited by Singh and Shukla, 2004).

147

Fig.4.2.2.6. Coal depositional environments based on the composition of microlithotypes (free of mineral matter). The analyzed coal samples indicate deltaic-lacustrine-fluvial environments (e.g., Singh and Singh, 1996; Singh and Shukla, 2004; Smyth, 2009).

4.2.2.3.2 Depositional environment of the Barapukuria and Dighipara Basin coals

The Permian Gondwana sediments of the Barapukuria and Dighipara half-grabens (Bengal

Basin) has been envisaged as derived from delta plain to fluvial (Alam et al., 2003; Islam and Hossain, 2006) based on the sedimentological analysis. Using organic geochemical parameters (in a biomarker study), Farhaduzzaman et al. (2011b and 2012a) proposed terrestrial oxic (dry) depositional conditions for the Permian coals. A predominantly delta- plain depositional environment and fluvial influenced lacustrine conditions have been visualized for the current study of the Permian coal samples, following the depositional model framed by Smyth (1984) and later cited by Singh and Shukla (2004) (Fig.4.2.2.6).

148 This interpretation is in fairly good agreement with the depositional scenario depicted by another depositional model constructed by Hunt (1982), where it suggests delta-plain

(mainly upper delta) depositional conditions (Fig.4.2.2.7).

Fig.4.2.2.7. A triangular diagram based on microlithotypes, illustrating the depositional environments. The analyzed samples represent the upper delta plain (mostly) to lower delta plain deposits (adopted by Hunt, 1982).

The dominance of inertinite macerals and absence of alginite maceral is an additional evidence for a terrestrial oxic (dry) depositional environmental, which is in agreement with the interpretation made of Hunt and Smyth (1989). Teichmüller (1974a), Cook et al. (1981) and Sherwood and Cook (1986) state that bituminite is considered to comprise the decompositional products of higher plants under oxic and anoxic depositional conditions.

149 The presence of bituminite in the current analyzed samples therefore corresponds to alternating oxic and anoxic depositional conditions (with sudden floods), which are indicated by the facies models used (Mukhopadhyay, 1986; Singh and Singh, 1996). The studied basins are known to be shallow (Imam, 2005; Islam and Hayashi, 2008). This is indicated by the high concentrations of inertinite macerals found in them such as semifusinite, fusinite and inertodetrinite. The shallowness of the basins is also demonstrated by the moderate presence of mineral matter, which indicates there were frequent dry spells (i.e., alternating oxic and anoxic conditions) during the evolution of the basin. On the other hand, the higher concentration of vitrinitic macerals indicates the development of coals beneath deeper basins. A variation in the depth of these basins is also suggested by the TPI values, as is discussed in subsection 4.2.2.3.1.3. Using isotopic analysis, together with a petrographic study of the Permian Gondwana coals of India, Singh et al. (2012c) has shown that those coals were deposited under the alternating oxic-anoxic environmental conditions (i.e., dry-wet). The results of the current investigation are similar, in that the studied Permian coals of Bangladesh were also deposited under oxic-anoxic mixed conditions. The influence of dry conditions is supported by the presence of inertinite macerals (especially structured macerals) and of wet conditions by the presence of vitrinite macerals.

The petrographic analysis of coal is important to understand the palaeofacies and palaeodepositional conditions of the peat/mire (e.g., Teichmüller and Teichmüller, 1982;

Holland et al., 1989; Mishra et al., 1990; Marchioni and Kalkreuth, 1991; Ratanasthien et al., 1999; Hower and Gayer, 2002; Singh and Shukla, 2004; Bechtel et al. 2004; Paul, 2005;

Shaver et al., 2006; Singh et al., 2010a and 2010b; Dutta et al, 2011; Farhaduzzaman et al.

2011b; Singh et al., 2012a and 2012b).

150 An attempt has therefore been made to reconstruct the conditions of coal formation in the

Barapukuria and Dighipara Basins on the basis of the maceral compositions and associations (microlithotypes) in the studied Permian coals. Facies and depositional conditions were investigated using petrography-based facies models, which have been used successfully in analyzing Permian Gondwana coals globally. Nevertheless, isotope analysis and a detail palynological study need to be carried out to investigate these coals further.

The current investigation is consistent with the interpretations relating to Indian and

Australian Permian coals.

A high concentration of inertinite and the low content of sulfide minerals (e.g., pyrite) is supported by the cross-plot of GI vs. TPI (terrestrial dry forest to piedmont plain depositional conditions) and GWI vs. VI (ombotrophic to mesotrophic hydrogeological conditions). As previously discussed, the terrestrial dry forest condition is known to be favorable for the development of more inertinite macerals in the coals, but is not congenial for sulfide mineralization. The dominance of structured inertinite macerals, such as fusinite and semifusinite, also indicate wild fire.

The variation of different maceral indices with a vertical depth pattern at the Barapukuria and Dighipara Basins is depicted in Fig.4.2.2.8. TPI, GI and VI values all increase with depth in both basins. However, the GWI value decreases with depth at Barapukuria but increases with depth at Dighipara. It indicates that a similar depositional condition prevailed at the time of deposition for both basins but that the groundwater level was fluctuating.

151

Fig.4.2.2.8. The variation of different maceral indices (TPI, GI, VI and GWI) with vertical depth patterns at the Barapukuria (BA, BB, BC and BD) and Dighipara (DA, DB, DC and DD). TPI, GI and VI values increase with depth in both basins. However, the GWI value decreases with depth at Barapukuria but increases with depth at Dighipara. It indicates that a similar depositional condition prevailed at the time of deposition for both basins, while the groundwater level is fluctuating.

152

Fig.4.2.2.9. Schematic block diagram represents the palaeodepositional environments of the Permian Gondwana coal deposits of the Barapukuria and Dighipara Basins, NW Bangladesh (Farhaduzzaman et al., 2012a).

Casshap and Tewari (1987) and Islam and Hossain (2006) demonstrated that the Gondwana sediments were laid down by laterally migrating river channels. The protected mires/lakes that formed the coals evolved in the poorly drained flood plains and peat swamps, which were densely vegetated, due to the tropical humid climatic conditions. This contention substantiates the interpretations made by the present authors. The peat that formed these coals was deposited under mostly oxic but with alternating oxic-anoxic moor conditions that evolved through fluvial-controlled deltaic (mainly upper delta) to lacustrine deposits, with sudden and frequent high floods. In this regard, based on the present study and supporting data reported by previous workers, a mixed (oxic-anoxic) dominantly terrestrial depositional environmental setting as shown in Fig.4.2.2.9 is proposed for the Barapukuria and Dighipara coals.

153 Chapter 4.2.3 Organic Geochemical Study of Coals and Associated Sediments

The organic matter compared to inorganic mineral matter (MM) can be considered to distinguish petrographically three organic-rich rock types. These are coals (MM<20 vol.%), carbargillites (MM 20-60 vol.%) and mudstones (MM>60 vol.%). The proportion of the organic versus inorganic content is also reflected in the TOC content. The coals, carbargillites and mudstones have TOC>40 wt.%, between 40-20 wt.% and <20 wt.% respectively. The present study is carried out based on organic geochemical and organic petrological methods using 36 core samples. Five different drill holes were chosen from two different coal basins. An attempt is taken to characterize the organic facies of currently studied coals, carbargillites and mudstones of these basins. Biomarker analysis (TIC, m/z

191 and m/z 217 fragmentograms) and maceral composition (proportions and properties of vitrinite, liptinite and inertinite) distinguishes three different organic facies of the studied samples: coals, carbargillites (as defined by Mackowsky, 1982) and mudstones.

4.2.3.1 Source rock properties

A summary of vitrinite reflectance (%Ro) and other organic geochemical data of the analyzed samples obtained from SRA are shown in Table 4.2.3.1. Rock-Eval pyrolysis

(RE) results of some selected samples are displayed in Appendix E1 for comparative evaluation. There is a good agreement between the results gained from SRA and those of

RE, enabling high confidence in the SRA results. The recorded TOC value (wt.%) ranges

44-78 (coals), 19-39 (carbargillites) and 4-9 (mudstones). HI varies from 113 to 310

(coals), 243 to 381 (carbargillites) and 65 to 158 (mudstones) mg HC/g TOC. It shows noticeable variation which infers a mixture of kerogen types (III/II) (see Appendices B1 and B3 for definitions).

154

155

Fig.4.2.3.1. Pictorial comparison of Tmax, HI and OI values found from two different methods SRA and RE. It shows a good agreement (see Appendix E1).

156 Peters (1986) showed the terrestrial organic matters (especially coals and coaly OM) of low maturity (%Ro less than 0.6%) produce large amounts of CO2 during pyrolysis. Here OI values are consistent with the corresponding atomic O/C. But some mature coaly organic matter show unusually low OI with values lower than expected based on the atomic O/C.

At higher levels of maturity, more pyrolytic oxygen releases as carbon monoxide which is not analyzed by SRA or Rock-Eval equipment. The recorded OI values of the currently analyzed samples are low. These can be caused by inadequate detection by the thermal conductivity detector (TCD) of CO generation during pyrolysis of this high maturity coaly organic matter as previously reported by Peters (1986), Hunt (1991) and Bordenave et al.

(1993). It may also be related to different types of organic matter (Koeverden et al., 2011).

Tmax values are close to each other and range from 431 to 438 °C (coals), 430 to 437 °C

(carbargillites) and 431 to 439 °C (mudstones). Based on the present analysis, a good quality source rock potential of the studied coal, carbargillite and mudstones is deduced following the classification adopted by Peters and Cassa (1994).

4.2.3.2 Macerals and kerogen type

A summary of the identified maceral composition viewed in the analyzed coal, carbargillite and mudstone samples are shown in Table 4.2.3.2. Inertinite (31-55 vol.%) is the dominant maceral followed by the vitrinite (19-39 vol.%) and liptinite (14-31 vol.%) group macerals with some inorganic mineral matter in the analyzed coal samples. Type III kerogen, represented by vitrinite, is the dominant maceral in carbargillites (19-35 vol.%) and mudstones (21-25 vol.%). Nearly equal amounts of liptinite (12-19 vol.% in carbargillites and 4-6 vol.% in mudstones) and inertinite (10-27 vol.% in carbargillites and 6-9 vol.% in mudstones) with large amounts of mineral matter are identified under microscope.

Carbargillite samples show higher liptinite contents (range 21-34 vol.% and mean 27

157 vol.%, mineral free basis) than coal samples (range 15-33 vol.% and mean 24 vol.%, mineral free basis).

158

Fig.4.2.3.2. Organic facies distribution from HI versus Tmax plot. The analyzed coals are dominated by Type III-II, carbargillites by Type II-III and mudstones by Type III organic matter. All the samples being early to mid-maturity thermal conditions (see Appendices B1 and B3 for definitions) (minor modification from Bjorøy et al., 1981; Davies and Nassichuk, 1988; Goodarzi et al., 1987; van Koeverden et al., 2011).

159 Significant amounts of Type II liptinite macerals are identified in all the studied samples.

The carbargillite samples show higher concentration of these liptinite macerals. Important liptinite macerals include sporinite, cutinite, resinite, bituminite, fluorinite and exsudatinite

(Table 4.2.3.2). The measured HI value of coals, carbargillites and mudstones varies in the ranges of 113-310, 243-381 and 65-158 mg HC/g TOC respectively. The higher value of HI in carbargillite is probably due to presence of more liptinite macerals. It suggests a higher oil and gas generation potential than the coals. A cross-plot of HI and Tmax shows the coals match to Type III-II kerogen (dominantly III), carbargillites to Type II-III kerogen, and mudstone to Type III kerogen (Fig.4.2.3.2).

Dembicki (2009) stated that besides other geochemical data (e.g., Rock-Eval), PyGC provides a good solution to interpret kerogen mixtures. This shows the direct hint of hydrocarbon types that can be generated by the kerogen during maturation. The >C15 fraction would be the least amount and

PyGC traces for the organic matter containing Type III kerogens. In case of Type I kerogens, it would be in reverse, i.e., highest >C15 fraction and least

Dembicki et al., 1983; Dembicki, 2009). Following these discussions, the mixed kerogen fingerprints of mainly n-alkane/alkene doublets and aromatic compounds are displayed by the whole rock PyGC pyrograms of the analyzed coal, carbargillite and mudstone samples

(Fig.4.2.3.3). These currently studied pyrograms show neither the typical signatures of

Type II nor Type III. Instead, they show the intermediate signatures of these two. It is known that type III kerogen composes mainly of vitrinite macerals with large amounts of inertinites. Type II kerogen consist mainly of liptinite macerals with large amounts of vitrinite macerals.

160 The observed PyGC pyrograms of coal samples correspond to dominating inertinite macerals mixed with large amounts of vitrinite and liptinites, thus more likely representing

75% Type III and 25% Type II (Dembicki, 2009) (Fig.4.2.3.3A). Similarly, the PyGC pyrograms of carbargillite samples containing dominant vitrinite macerals with considerable amount of liptinites represent 50% Type II and 50% Type III (Fig.4.2.3.3B).

The mudstone samples with dominant vitrinites correspond mostly to Type III kerogen

(Fig.4.2.3.3C). The relative abundance of aliphatic to aromatic hydrocarbons may be quantified by the ratio of n-octene (C8) to (m+p)-xylene. The calculated C8/xylene ratio is low which ranges from 0.73 to 0.89. The analyzed samples show high profusion of aromatic hydrocarbons (for example, benzene, toluene and xylene) relative to n- alkanes/alkenes (i.e., low C8/xylene ratio) in the pyrograms. It implies the higher input of humic materials in the source. The dominant inertinite macerals correspond to vascular higher plants, which represents the terrestrial environment of deposition.

4.2.3.3 Soluble extract and biomarker distributions

A summary of extractable organic matter (EOM) of the analyzed samples is shown in Table

4.2.3.3. The total amount of EOM is high in coal samples (13811-46529 ppm) compared to those of carbargillite (5182-24241 ppm) and mudstones (1704-2991 ppm). Hydrocarbon in extract (%) for all the three groups of samples is similar. Aromatic hydrocarbon fraction is higher than the aliphatic in all the analyzed samples. The values of calculated hydrocarbon yield (aromatic>aliphatic) are also close to one another. These are 17-34 mg EOM/g TOC in coal, 11-34 mg EOM/g TOC carbargillite and 20-23 mg EOM/g TOC mudstone samples.

A significant amount of NSO is measured in all the samples.

161 The NSO fraction is higher than that of total hydrocarbons (aliphatic and aromatic) in most of the coal samples. It is higher than the aliphatic or aromatic in carbargillite or mudstone samples (Table 4.2.3.3).

The aliphatic fractions of selected coal, carbargillite and mudstone samples are analyzed by

GCMS. The peaks in GCMS are identified assuming mass spectra as well as comparing with published literature. For example, Philp (1985) and Pearson and Alam (1993) for TIC;

Fabianska et al. (2003), Ahmed et al. (2009) and Kashirtsev et al. (2010) for m/z 191 fragmentograms; and Abeed et al. (2011), Koeverden et al. (2011) and Sachse et al. (2012) for m/z 217 fragmentograms.

162

Fig.4.2.3.3. PyGC pyrograms of the analyzed coal, carbargillite and mudstone samples representing Type III/II (dominant Type III), Type II/III mixture and Type III kerogen respectively (c.f., Dembicki, 2009).

163

4.2.3.3.1 GC: TIC (Total Ion Current)

The TIC (total ion current- full scan), m/z 191 and m/z 217 chromatograms of the representative three samples (coal, carbargillite and mudstone) are shown in Figs.4.2.3.4,

4.2.3.5 and 4.2.3.6. A long range of n-alkanes ranging from nC10 to nC40 are identified in

TIC fragmentograms of all the analyzed samples. These are dominated by medium to high molecular weight (nC16-nC27) n-alkanes (Figs.4.2.3.4A, 4.2.3.5A and 4.2.3.6A; Appendices

E2 and E3).

164

4.2.3.4. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied coal sample (BPCL15) of the Barapukuria Coal Basin (peak i.d. in Appendix B2).

165

4.2.3.5. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied carbargillite sample (DPCR42) of the Dighipara Coal Basin (peak i.d. in Appendix B2).

166

4.2.3.6. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied mudstone sample (BPMT22) of the Barapukuria Coal Basin (peak i.d. in Appendix B2).

167 The n-alkane maxima are found at nC18-nC25 in coal and mudstone samples. It is mostly at nC25 in carbargillite samples, thus, representing more waxy appearance. The calculated peak height of pristane in all the analyzed samples is higher than that of nC17. The peak height of phytane is lower than that of nC18. The ratio of Pr/Ph is high (4-9) found in the analyzed coal, carbargillite and mudstone samples. Compared to carbargillites, the higher value of Pr/Ph in coal samples is likely because of strong terrestrial influence. The odd carbon-numbered n-alkanes are dominant over the even carbon-numbered members noted in TIC. Thus, CPI value is always higher than the unity.

4.2.3.3.2 GCMS: m/z 191 Fragmentogram

The m/z 191 mass chromatograms of the aliphatic hydrocarbon fractions are analyzed for all the three groups of sediments. They shows abundant pentacyclic triterpanes with trace amount of tetracyclic terpanes (Figs.4.2.3.4B, 4.2.3.5B and 4.2.3.6B; Appendices E2 and

E3). Comparing the peak intensities, the pentacyclic triterpanes in coals are more abundant than those in mudstones or carbargillite (coal ˃ mudstone ˃ carbargillite). The C30αβ- hopane is the dominant hopane. The C31αβ-hopane is the most abundant compound among the homohopanes in all the three group of sediments analyzed. A large amount of C30βα- hopane and C29βα-hopane (moretanes) compared to their αβ-compounds is found in the analyzed samples. The Tm/Ts ratio of carbargillite samples is slightly lower than those of coal and mudstone samples (Table 4.2.3.4). The C35 homohopane index is very low (0.03-

0.06) in all the analyzed samples.

168

4.2.3.3.3 GCMS: m/z 217 Fragmentogram

The m/z 217 fragmentograms show high relative abundance of C29 regular sterane than the

C28 or C27 sterane in coal and mudstone samples (Figs.4.2.3.4C and 4.2.3.6C; Appendix

E2). Near equal abundances of C27 and C29 regular steranes are found in the carbargillite samples (Figs.4.2.3.5C and Appendix E3). The comparative abundance (peak height) of diasterane is slightly higher in carbargillite and mudstone samples than those of coal

169 samples. The diasterane/sterane ratio varies from 0.03 to 0.09, 0.04 to 0.22 and 0.14 to 0.24 in the analyzed coal, carbargillite and mudstone samples respectively (Table 4.2.3.5). The calculated sterane/hopane ratios of the studied samples are close to one another. It varies from 0.2 to 0.5, which points out the hopane compounds are much higher compared with steranes.

4.2.3.4 Discussion

4.2.3.4.1 Thermal maturity of the organic matter

The measured mean vitrinite reflectance (%Ro) of coals and carbargillites is 0.70-0.80 and

0.66-0.81, respectively. Coal samples are of high volatile bituminous B rank (Stach et al.,

1982), representing an early mature oil window. The %Ro varies from 0.60 to 0.76 (%Ro) in the mudstone samples, suggesting early to peak oil-window maturities following the classification adopted by Peters and Cassa (1994). Tmax values of 429.8-438.1 ˚C for coals,

429.6-437.2 ˚C for carbargillites and 430.8-439.2 ˚C for mudstone samples likewise indicate early to peak maturities (see Appendix B3 for standard parameters and values)

(Peters and Cassa, 1994; Petersen, 2002). However, the values of Tmax and vitrinite reflectance are likely suppressed due to significant presence of liptinite with dominant Type

III organic matter in the coal and carbargillite samples (c.f., Hunt, 1991; Hunt and Hennet,

1991; Snowdon, 1995; Petersen, 2006). However, following the maturity interpretation for coals by Petersen (2006), the organic matter in the studied coals marks immature to early mature oil window. A homohopanes ratio 22S/(22S+22R) (i.e., C31- or C32-homohopanes) of about 0.60 is considered to be an equilibrium value for oil window maturity. The calculated homohopanes ratio 22S/(22S+22R) (C31- or C32-homohopanes) of the analyzed samples ranges from 0.55 to 0.61, implying an immature to early thermal maturity stage.

170 The bimodal distribution of TIC fingerprints of the analyzed samples is in good agreement with this immaturity assessment. The samples’ diasterane 20S/(20S+20R) ratios of 0.58-

0.77 also support their immature to early maturity level for hydrocarbon generation (Peters and Moldowan, 1993). Other maturity related biomarker ratios such as moretane/hopane,

C35 homohopane index, diasterane/sterane, sterane C29 20S/(20S+20R) and sterane C29

ββ/(ββ+αα) do not show any substantial variation among the analyzed samples nor show correlation with the vitrinite reflectance data. The thermal maturity of the organic matter of any sediment governs, in part, the properties of organic matter and, therefore, can influence interpreting organic facies (Peters et al., 2005; Wan Hasiah, 1999a). Therefore, the biomarker fingerprints presented here are believed to have influenced by the facies difference, particularly source input and the depositional conditions of the organic matter. It is duly explained in the subsection 4.2.3.4.2 below.

Fig.4.2.3.7. Organic facies related triangular diagram based on C27, C28 and C29 regular sterane epimers. The analyzed coal samples correspond to mainly terrestrial organic matter with minor contribution from marine source. The carbargillite samples indicate mixed terrestrial and marine influenced sources and mudstones to terrestrial organic source (e.g., Waples and Machihara, 1991).

171 4.2.3.4.2 Organic facies characteristics

Biomarkers derive from biological precursor molecules in specific organisms. Each of these organisms lives only under specific conditions. So, it is logical to use biomarkers as indicators for both terrestrial and aquatic photosynthetic biota (Waples and Machihara,

1991). Steranes and triterpanes together can provide important clues about the organic facies. Huang and Meinschein (1979) and Pedersen et al. (2006) reported the relative proportions of C27, C28 and C29 regular steranes (20R epimers) suggest valuable paleoenvironmental information. The dominant C29 corresponds to terrestrial facies and dominating C27 suggests marine depositional condition.

Fig.4.2.3.8. A cross-plot of pristane/nC17 versus phytane/nC18 for the currently explored coal, carbargillite and mudstone samples. It represents the sub-oxic depositional conditions with dominantly terrestrial organic matter (c.f., Peters et al., 2005).

The framed triangular plot based on the currently analyzed coal, carbargillite and mudstone samples showing dominant C29 sterane over C27 or C28 marks the predominating terrestrial organic facies within the depositional system (Fig.4.2.3.7).

172 However, the relative proportion of C27 of the carbargillite samples is higher than those of coals and mudstones. Thus, significant amount of marine organic matter would have present during the deposition of the Permian carbargillites (Figs.4.2.3.4C, 4.2.3.5C and

4.2.3.6C; Appendices E2 and E3; Fig.4.2.3.7). Petrographically, it is also supported by a higher presence of liptinitc macerals in carbargillites compared with coals and mudstones.

The dominant terrestrial organic facies for the analyzed coal, carbargillite and mudstones are also shown by the cross-plot of Pr/nC17 versus Ph/nC18 (Fig.4.2.3.8). This points to an alternating oxic-anoxic depositional condition prevailed during that geological time. Powell and McKirdy (1973) and Philp (1985) reported the pristane forms in oxidizing condition and phytane in reducing environment. Therefore, the high value of Pr/Ph ratio (>3) shown by the analyzed samples also suggests the suboxic depositional condition of terrestrial environment. The dominated inertinite macerals provides further support to this condition during the deposition of these analyzed samples.

Brooks (1986) and Ramanampisoa et al. (1990) noted that high concentration of C29 hopane

(C29/C30) indicates a terrestrial depositional facies. There is an overall high content of C29 hopane in all the analyzed samples, suggesting the dominant presence of terrestrial derived organic matter. The C29/C30 ratios of the analyzed carbargillite samples show slightly lower values (0.8-0.9) compared to those of coals (0.8-1.2) and mudstones (0.8-0.1), also indicating that the coal and mudstone samples have stronger terrestrial organic inputs than the carbargillites. A minor contribution from marine derived facies is also suggested by the relatively lower value of C29/C30 in some of the analyzed coal samples (BPCL9, BPCL24 and BPCL28).

173

Fig.4.2.3.9. Environmental depositional conditions of coals and carbargillites based on the maceral and mineral matter contents (adopted by Singh and Singh, 1996). The analyzed coal samples fall within alternating oxic-anoxic swamp. The carbargillite samples fall within the wet swamp with intermittent and moderate to high flooding.

In the studied samples, there is a general decrease in peak heights of the homohopanes from

C31 to C35 (C31˃C32˃C33˃C35) (Figs. 4.2.3.4B, 4.2.3.5B and 4.2.3.6B). This, in turn, corresponds to terrestrial organic facies. The relative large amount of C34 hopane in the analyzed samples also agrees with the interpretation of strong terrestrial influence (Waples and Machihara, 1991). It is supported by low C35 homohopane indices (0.03-0.06) among the examined coal, carbargillite and mudstone samples (Peters et al., 2005). The high

Tm/Ts ratio of the analyzed samples suggests a terrestrial sourced organic facies. But the

Tm/Ts ratio of the carbargillite samples (5-12) is slightly lower than those of coals (8-13) and mudstones (6-21), supporting a mixed organic facies for the analyzed samples.

174 The coals and mudstones contain stronger terrestrial organic facies indicators than the carbargillites. The high value of Tm/Ts may indicate an oxic-anoxic depositional condition for the analyzed samples (Moldowan et al., 1986). The abundant moretane

(moretane/hopane = 0.3-0.5) of the studied coal, carbargillite and mudstone samples is also consistent with the strong terrestrial organic facies (Connan et al., 1986). The presence of tetracyclic is a further support (Philp and Gilbert, 1986). Tissot and Welte (1984),

Moldowan et al. (1986) and Clifton et al. (1990) reported that sterane/hopane ratio ≤1 typifies terrestrial organic facies. The measured very low sterane/hopane ratio of the analyzed samples points to dominating terrestrial higher plant and fungal material organic inputs. The higher value of sterane/hopane is found in the studied carbargillite samples

(0.4-0.5) compared with coals (0.3-0.4) and mudstones (0.2-0.4). It again marks some contribution from different organic source inputs (possibly marine derived organic matter) compared to the dominantly terrestrial organic facies. Some of the coal samples (BPCL24,

BPCL28 and DPCL40) with high value of sterane/hopane ratio also suggest a minor contribution from a marine influenced depositional environment. The dominantly terrestrial organic facies is further supported by the distributions of n-alkanes with the marked predominance of odd carbon-numbered homologs to even carbon-numbered homologs in n- alkanes. This is indicated by CPI1 values of 1.06-1.54 and shown in Appendix E4.

The triangular plot from petrological data suggests an alternation of oxic to anoxic swamp for coal deposition (Fig.4.2.3.9), while the carbargillite matches to a wet swamp with intermittent to moderate high floods (Singh and Singh, 1996). The presence of micro and mega sporinite (both thin and thick walled), micro and mega cutinite (both thin and thick walled) and micro and mega resinite of the analyzed coal and carbargillite samples also support more than one organic input to the depositional system.

175 The cross-plot of HI versus Tmax supports the assumption of a mixture of organic input within the analyzed coals that are dominated by terrestrial Type III-II kerogen. The carbargillites show a mixture of terrestrial and marine (Type II-III) kerogens and mudstones

(Type III kerogen) are dominated by terrestrial organic facies. Such kerogen assemblages indicate that their deposition has taken place under oxic-anoxic condition. Here is a good agreement with the organic facies interpretation from biomarker characteristics as well as petrography. In addition, the dominancy of aromatic hydrocarbons in the extract of the analyzed coal, carbargillite and mudstone samples is in support of the strong terrestrial organic inputs to the depositional system during Permian time.

4.2.3.4.3 Hydrocarbon generation and expulsion

Over the last three decades, a long debate has been continuing among the scientists regarding the issue of generating and expelling hydrocarbon from coals. However, authors such as Snowdon and Powell (1982), Teichmüller and Durand (1983), Price and Barker

(1985), Murchison (1987), Hunt (1991), Newman et al. (1997), Wan Hasiah (1997 and

2003), Petersen et al. (2000 and 2005) and Wilkins and George (2002) have published many papers in support of hydrocarbon generation and expulsion from coals. Now it is accepted the terrestrially derived organic matter from coal and coaly organic matter can generate commercial volumes of liquid hydrocarbon. The Kutei Basin of Indonesia

(Thompson et al., 1985) and the Gippsland Basin of Australia (Thomas, 1982) are among the examples. However, generation is dependent on many different interrelated factors such as organic matter type, maturity, matrix property, depositional settings and coal age

(Petersen and Nytoft, 2006). The liptinite macerals with perhydrous vitrinite in the coals are considered as the most important constituents for hydrocarbon generation as reported by these workers.

176 Hood et al. (1975) and Tissot and Welte (1984) reported the generation of hydrocarbon in most source rocks is considered to begin in the sub-bituminous A coal stage, which is equivalent to about 0.5 %Ro. But the actual expulsion of hydrocarbons begins in the high volatile bituminous coal stage which is equivalent to 0.7 %Ro for Cenozoic coals (Wan

Hasiah, 2003; Petersen, 2006). For Permian coals, Petersen (2006) proposed the expulsion threshold at a vitrinite reflectance of 0.85-0.90 %Ro or Tmax of 440-445 °C. The coals analyzed here have %Ro of 0.70-0.80 and Tmax of 430-438 ˚C and may, therefore, have generated and possibly expelled hydrocarbon. The considerable presence of liptinite macerals could have lowered the expulsion threshold in these coal samples. The vitrinite reflectance value of 0.6 (%Ro) and Tmax of 435 °C has been suggested as the start of oil window by Peters and Cassa (1994). Based on this interpretation, the analyzed mudstone and carbargillite samples holding %Ro of 0.60-0.81 and Tmax of 430-439 °C have generated and possibly expelled hydrocarbons at their peak maturity stage.

The examined coal, carbargillite and mudstone samples with noticeable amounts of liptinite macerals would have generated and possibly expelled the hydrocarbon. Because these samples are registered in early to peak thermal maturity range based on %Ro of 0.60-0.81 and Tmax of 430-439 ˚C (Farhaduzzaman et al., 2011a and 2012c). The presence of exsudatinite in the terrestrially derived samples analyzed is evidence of hydrocarbon generation (Teichmüller, 1974b). The exsudatinite within crack network appears to have developed in these samples and shows the liptinitic materials have already expelled their liquid hydrocarbon constituents to the carrier bed (Wan Hasiah, 1999b) (Photomicrograph

4.2.3.1A1 and A2).

177

Photomicrograph 4.2.3.1. (A1) Low reflecting dark brown exsudatinite (ex) with crack network associated with vitrinite (vt), micrinite (mi), sporinite (sp) and inertinite (in) whereby this type of network is considered as probable conduits for hydrocarbon expulsion/migration as observed under reflected white light. (A2) Same view as A1 whereas the exsudatinite has expelled most of the liquid hydrocarbons therefore showing a dull brown fluorescence under ultraviolet light. (B1) Reddish brown indigenous solid bitumen (sb) which is considered as ‘free’ hydrocarbon observed under reflected white light, dark brown resinite (re) is also shown. (B2) Same view as B1 while solid bitumen shows dull brown fluorescence and resinite shows brownish yellow fluorescence under ultraviolet light (Caption continued next page).

178 Photomicrograph 4.2.3.1 (Caption continued). (C1) Dark brown color fluorinite (fl) both as dispersed and continuous form together with brown color cutinite (ct) and moderate grey vitrinite (vt) under normal reflected white light. (C2) Same view as C1 under ultraviolet light whereas the fluorinite shows brilliant yellow fluorescence and also occur as oil droplets and cutinite shows dull brown fluorescence (Note: Samples are studied under oil immersion objective whereby similar maceral types but different proportions are identified in all the coal, carbargillite and mudstone samples).

The indigenous solid bitumen found in the analyzed samples also suggests the generation and expulsion of hydrocarbon from these samples have occurred (Photomicrograph

4.2.3.1B1 and B2). The fluorinite is commonly considered to be free oils and these are observed as oil droplets in the studied samples under ultraviolet light excitation

(Photomicrograph 4.2.3.1C1 and C2). Resinite, bituminite and cutinite macerals are the most significant liptinite to play important role in hydrocarbon generation (Teichmüller and

Durand, 1983). The considerable amounts of resinite, bituminite and cutinite identified in the currently analyzed samples suggest good hydrocarbon (both liquid and gas) generation potential (Photomicrograph 4.2.3.2A1 and A2; B1 and B1; C1 and C2). Newman et al.

(1997) reported that the fluorescent (perhydrous) vitrinite can also generate liquid hydrocarbons, for example, in the Gippsland Basin of Australia. It is observed in the presently analyzed samples (Photomicrograph 4.2.3.3A1 and A2). Micrinite is considered to be the residue of hydrocarbon generation (Teichmüller and Durand, 1983). The significant presence of micrinite (Photomicrograph 4.2.3.3B) in the analyzed samples suggests the organic matter has already expelled liquid hydrocarbons in the associated

Gondwana Petroleum System.

179

Photomicrograph 4.2.3.2. (A1) Brownish oval to rounded most oil-prone maceral resinite (re) associated with medium grey vitrinite (vt) under normal reflected white light. (A2) Same view as A1 under ultraviolet light whereas the resinite shows yellowish green fluorescence. (B1) Brownish megasporinite (sp) and another oil-prone structureless maceral bituminite (bt) associated with vitrinite (vt) and inertinite (in) under reflected white light. (B2) Same view as B1 under ultraviolet light whereas sporinite showing greenish yellow fluorescence and bituminite showing dull yellow fluorescence. (C1) Oil- prone brownish micro and mega cutinite (ct) associated with dark brown fluorinite (fl) and medium grey vitrinite (vt) under reflected white light. (C2) Same view as C1 under ultraviolet light whereby the cutinite fluoresces dull brown color and fluorinite fluoresces brilliant yellow in the form of oil droplets (Note: Samples are studied under oil immersion objective whereas similar maceral types but different proportions are identified in all the coal, carbargillite and mudstone samples).

180

Photomicrograph 4.2.3.3. (A1) Light grey fluorescent vitrinite (fv) associated with darker grey vitrinite under normal reflected white light. (A2) Same view as A1 under ultraviolet light showing yellow cuticle and greenish yellow fluorescence haze which indicate the presence of generated hydrocarbon. (B) Whitish (B1) micrinite under normal reflected white light (B2- dark in UV light) and it is believed that these are the residual products formed after hydrocarbon expulsion from the hydrogen rich constituents. (C1) Reddish brown mega and micro sporinite (sp) associated with vitrinite (vt) under normal reflected white light. (C2) Same view as C1 under ultraviolet light and it shows intense yellow fluorescing megasporinite (Note: Samples are studied under oil immersion objective and similar maceral types but different proportions are identified in all the coal, carbargillite and mudstone samples).

181

Fig.4.2.3.10. A cross-plot of TOC versus S2 in which all the analyzed samples fall within the range of fair to excellent hydrocarbon generation potential. Mudstone indicates the lowest potential and followed by carbargillite and coals (adopted by Peters and Cassa, 1994; Dembicki, 2009; cited by Farhaduzzaman, 2012a).

The relative higher content of liptinite macerals in the carbargillites compared with the coals and mudstones suggest the carbargillites and coals may possess some oil-generating potential, but they are predominantly gas-prone, while the mudstone samples are gas-prone.

Peters and Cassa (1994) showed a source rock classification scheme ranging from poor

(TOC ˂0.5%; S2 ˂2.5) to excellent (TOC ˃4%; S2 ˃20) based on Rock-Eval S2 and TOC contents. The measured TOC content of the analyzed samples are 44-78 wt.% (coal), 19-39 wt.% (carbargillite) and 4-9 wt.% (mudstone). The Rock-Eval S2 values are 71-188, 63-107 and 4-15 mg HC/g rock for the studied coal, carbargillite and mudstone samples, respectively.

182 An overall good hydrocarbon generation potential is estimated based on a cross-plot of

TOC (wt.%) versus S2 (mg HC/g rock) for the analyzed samples. The coals and carbargillite are in the “excellent” category and mudstones are “fair-good” category source rocks (Fig.4.2.3.10). Although the coal and carbargillite samples are rich in inertinite, they also contain considerable amounts of liptinite macerals. Thus, they have petroleum source potential as reported by Powell et al. (1991) and Smyth (2009) for the Cooper Basin,

Australia.

Frielingsdorf et al. (2008) mentioned the Permian Gondwana coal of northwest Bangladesh is the major petroleum source rock in the region, having already released up to 29% of its generation potential. It is also interesting to add the entire hydrocarbon discovery in the

Bengal Basin, Bangladesh has consisted mainly of natural gas with minor oil (Imam, 2005).

Therefore, this is in good agreement with the present hydrocarbon generation and expulsion potential of the analyzed samples.

183

4.3 PETROLEUM RESERVOIR ROCK- SANDSTONES

4.3.1 Petrography and Diagenesis of Sandstones

4.3.2 Petrophysical Study of the Well Rashidpur 4

184 CHAPTER 4.3.1 PETROGRAPHY AND DIAGENESIS OF SANDSTONES

The studied sandstone reservoir units belong to Miocene-Pliocene Surma Group in the

Bengal Basin, Bangladesh (RPS Energy, 2009). The Surma Group sandstone deposited in deltaic to marine environment and, in general, has good porosity and permeability and this hosts all of the petroleum resources discovered so far in Bangladesh. A total of 33 core samples collected from eight different wells located in seven different gas/oil fields of

Bangladesh are used for the current petrographic and diagenetic study. Here, the standard petrographic microscope, scanning electron microscope (SEM/FESEM) and XRD are used.

4.3.1.1 Sandstone texture and sorting

The investigated Surma Group sandstones are very fine to medium grained. The very fine grained to fine grained nature is observed especially for the sandstones of Kamta Filed.

Predominantly subrounded to subangular grains are observed in the studied sandstone samples along with the common presence of rounded grains. The subangular nature is found especially among the smaller grains, whereby the larger grains show better rounded nature. The feldspar grains are observed mostly as subangular to even angular nature, especially in subfeldspathic arenite types. The examined grains are observed moderately well sorted to well sorted. The studied sandstones are mature in textural point of view

(Folk, 1980).

4.3.1.2 Sandstone composition

Particle composition is a fundamental physical property of the sandstones and is the chief property used in their classification and provenance interpretation. Particle composition may also influence the economic importance of sandstones as hydrocarbons (oil and gas) reservoirs. It has a considerable contribution on the course of diagenesis in sandstones and,

185 thus, ultimately impacts the porosity and permeability of the particular sandstones (Boggs,

2009). Sand and silt size particles constitute the framework fraction of the analyzed sandstones. It also contains various amounts of matrix (material less than 0.03 mm) and cement present within the interstitial pore spaces among the framework grains.

Authigenic minerals that replace some framework grains, matrix or cement are also observed in the studied thin sections of sandstones. The empty pore spaces (porosity), both connected and unconnected, are also found under microscope. The compositional description of the investigated Surma Group sandstones is added below.

186 Framework grains

The studied Surma Group sandstones are composed of a variety of major detrital minerals and rock fragments (labile lithic grains) together with some accessory minerals (Table

4.3.1.1). Detrital constituents are defined as those derived by mechanical and chemical disintegration of a parent rock. The observed detrital constituents are terrigenous siliciclastic particles that are generated through the process of weathering, explosive volcanism and sediment transport from parent rocks located outside the depositional basin.

Accordingly, the framework grains of the analyzed sandstone samples are composed of predominantly of quartz (76-91%) and nearly equal amounts of feldspar (3-14%) and rock fragments (5-16). Several other detrital minerals such as chlorite, muscovite, biotite, calcite and heavy minerals are also found in lesser amounts of the investigated samples.

Quartz (Q): The principal silica crystalline mineral identified in the studied sandstones is the quartz. It is distinguished optically by its grey interference color and low birefringence along with uniaxial positive sign (Photomicrograph 4.3.1.1A). Many quartz grains display undulatory extinction, which is a pattern of sweeping extinction as the microscope stage is rotated (Photomicrograph 4.3.1.1A). Basu et al. (1975) differentiated undulatory quartz with extinction angle higher than 5 degrees while others are nonundulatory quartz. The bubbles or mineral inclusions are found in many of the analyzed quartz grains. The bubbles are also known as vacuoles seemed to filled with liquid, liquid and gas or gas alone. These bubbles are randomly distributed throughout the quartz grains in most cases

(Photomicrograph 4.3.1.1A). However Folk (1980) stated that the quartz crowded with bubbles to the point that it appears milky in reflected light is probably derived from hydrothermal veins.

187

Photomicrograph 4.3.1.1. (A) The most abundant both kinds of quartz (Qm and Qp) show grey interference color in association with chert (Ct) consisting of numerous microquartz grains. Several quartz grains (dark grey) show undulatory extinction and few show vacuoles (V). Microcline (M) shows cross-hatched twining attached with brownish mica (Bi). Other commonly found sedimentary rock fragment (Ls) and metamorphic rock fragments (Lm), depth 3025m at Kamta well-1 (KM1ST9. (B) Rounded quartz grain shows overgrowth separated by its thin clay rim ‘dust line’. Dark green chlorite cement (Ch) also observed between grains, depth 3379m at Kamta well-1 (KM1ST11). (C) Different kinds of grain contacts between quartz grains- long contact (LC) correspond relatively to early stage of diagenesis whereby concavo- convex (CC) and suture contacts (SC) represent intermediate stage of diagenesis. Mica inclusions (Ic) also shown, depth 3578m at Begumganj well-1 (BG1ST19) (Continued).

188 Photomicrograph 4.3.1.1 (Continued). (D) Fibrous variety of quartz, chalcedony (Chal), rarely found. Quartz overgrowth (QO) also showed, depth 2670m at Rashidpur well-4 (RP4ST8). (E) Plagioclase feldspar (P) identified by its albite twining. Altered alkali feldspar (K) and its dissolution (Diss) also shown. Mold as secondary porosity (SP) also found, depth 2401.5m at Kailas Tila well-5 (KT5ST7). (F) Perthitic texture distinguished by patchy intergrowth of albite into the orthoclase. Dark green chlorite (Ch) cement rims the quartz grain. Brownish biotite is altering to greenish chlorite (Bi-Ch), depth 2699m at Titas well-11 (T11ST23).

Thus, the presence of sparse vacuoles in quartz appears to have no provenance significance.

Tiny mineral inclusions are common in quartz; including micas, chlorite, zircon, apatite and rutile although it is very difficult to identify these minerals using the ordinary petrographic microscope. Smaller quartz grains of the studied samples are relatively subangular to subrounded, whereas, many of the larger grains are rounded in shape. Silica overgrowths are observed onto the original surfaces of these rounded quartz grains in the presence of open pore space. The original grain outline is commonly revealed by the presence of small specks of hematite, clay or other mineral rim ‘dust line’ (Photomicrograph 4.3.1.1B).

However, all these overgrowths are not marked by this kind of clay rim and, in fact, it is more clearly identified by scanning electron microscopy (described in the next section).

Monocrystalline quartz occurs preferentially as sand-size individual crystals in the analyzed samples. Polycrystalline quartz, also known as composite quartz, is very common in the studied sandstone thin sections. It is actually made up of aggregates of two or more quartz crystals (Photomicrograph 4.3.1.1C). The individual crystals within a polycrystalline grain are equant or elongate in shape, fine grained or coarse grained and even same size or variable in size. The observed grain contacts or crystal boundaries are straight, concavo- convex and sutured to various degrees (Photomicrograph 4.3.1.1C).

189 The fibrous variety of quartz, chalcedony, is also found in the studied sandstones although it is very rare because of its unstable nature on weathering (Photomicrograph 4.3.1.1D).

Quartz is the most stable, dominant and widespread constituent in the sandstones. It is thought to have generated from felsic plutonic rocks. The older sedimentary rocks also contribute to its content in sandstones (Folk, 1980).

Feldspar (F): Feldspar and rock fragments are identified almost in equal abundances after quartz in the analyzed samples (Table 4.3.1.1). They can be divided into two main groups: alkali feldspars (potassium feldspars) and plagioclase feldspars. Both of the groups are well preserved in the studied Surma Group sandstone samples. The content of plagioclase feldspar (0.4-5.9%) is almost equal to those of alkali feldspars (1.6-6.3%). Orthoclase and microcline are the most abundant members identified in the alkali feldspar group of the samples under microscope. Albite is the most dominant and easily identifiable member of the plagioclase group.

Untwined orthoclase appears very similar with quartz in thin section and it is a bit difficult to identify properly. However, orthoclase is distinguished by its relatively lower birefringence than quartz and apparent cleavage faces (Photomicrograph 4.3.1.1E). It is cloudy or pale brownish color (because of alteration) in plane polarized (PPL) view while the quartz is usually clear and unaltered. The twined microcline is easy to recognize in thin section owing to the common presence of its distinctive ‘grid’ or ‘cross-hatch’ twining with the two sets of twin lamellae approximately at right angles to each other (Photomicrograph

4.3.1.1A).

190 Alkali feldspars are thought to have derived particularly from alkali and acid igneous rocks and are especially abundant in syenites, granites, granodiorites and their volcanic equivalents. They occur also in pegmatites and acid and intermediate composition metamorphic rocks such as gneisses (Boggs, 2009).

Most of the plagioclase feldspars are easily identified by their characteristic albite twining with lamellae that are straight and parallel to each other (Photomicrograph 4.3.1.1E). Both twined-untwined and zoned-unzoned plagioclases are observed in the samples analyzed.

Perthitic intergrowths are observed frequently in the studied samples. Perthitic intergrowth is microcline or orthoclase characterized by patchy intergrowths of albite in the form of small strings, lamellae, blebs, films or irregular veinlets (Photomicrograph 4.3.1.1F).

The principal source for detrital plagioclase is probably basic and intermediate lavas where it occurs as phenocrysts. It may also be derived from basic intrusive rocks and is a very common constituent of many metamorphic rocks where its composition is related to the metamorphic grade of the host rock (Boggs, 2009).

Coarse micas: The principal coarse micas identified as detrital grains in the analyzed

Surma Group sandstones include muscovite and biotite. Folk (1980) stated that muscovite is chemically more stable than biotite and accordingly the content of muscovite (0.8-8.7%) is slightly higher than that of biotite (0.2-6.2%) in the analyzed sandstones (Table 4.3.1.1).

Another detrital grain chlorite is not uncommon in the studied samples although it is in lesser amounts. The micas are distinguished from other associated minerals by their typical platy or flaky habit (Photomicrographs 4.3.1.1F and 4.3.1.2A). Rounded micas are rare and they are commonly deposited with their flattened dimension parallel to the bedding.

191 The bending of mica flakes is also found in the studied samples (Photomicrograph

4.3.1.2A). Muscovite is colorless in thin section. Biotite is observed as yellow, brown or green in color and can be leached pale yellow or almost colorless in some cases. Muscovite does not show any pleochroism whereas biotite shows strong pleochroism along with the parallel extinction. Both muscovite and biotite are found with moderately high birefringence in second order reds, blues and greens. Chlorites are characterized by their green color and pleochroism in the studied these sections. They are distinguished from the associated minerals by anomalous interference colors, particularly in blues. The transformation from biotite to green chlorite is frequently found in the studied sandstone samples (Photomicrograph 4.3.1.2A). The identified detrital chlorite is common in all of the studied sandstone samples although its content is very low (trace to1.5%).

Boggs (2009) suggested that the micas and chlorite are derived primarily from metamorphic rocks but biotite occurs also in basic intrusive and volcanic rocks and in granites. Muscovite occurs in granites and pegmatites as well.

Rock fragments (L): Rock fragments, also known as labile lithic grains, are detrital particles made up of two or more mineral grains. The abundance of rock fragments depends on several factors such as grain size, lithology and source area provenance etc (Dickinson,

1985; Boggs, 2009). For example, sandstone with coarse grains contains higher amount of rock fragments than those with finer grains. Almost all kinds of rock fragments are observed in the investigated thin section of the Surma Group sandstones. Nonetheless, the content of metamorphic rock fragments (3.4-10.5%) is higher than that of sedimentary

(trace to 4.2%) or volcanic (trace to 0.8%) rock fragments in the analyzed samples.

192 The most common igneous rock fragment is volcanic rock fragments with porphyritic and aphanitic texture. The lathwork grains (volcanic rock fragments) are recognized by the plagioclase laths forming intergranular and insertal (triangular patches of interstitial glass between feldspar laths) texture (Photomicrograph 4.3.1.2B). It is derived mainly from basaltic lavas. Metamorphic rock fragments are characterized by the schistose, semischistose or slaty fabric resulting from preferred orientation of recrystallized mineral grains (Photomicrograph 4.3.1.2C). The higher presence of quartz and mica indicates the metasedimentary rock fragment. Metamorphic rock fragments include schist, phyllite, slate and quartzite with foliated fabric. Shale, siltstone and chert with fragmental or microgranular texture are the most commonly found sedimentary rock fragments although cherts are included in the polycrystalline quartz (Photomicrographs 4.3.1.2.C and 4.3.1.1E).

Chert is distinguished by the microgranular texture composed entirely of quartz

(Photomicrograph 4.3.1.2C).

The rock fragments are derived from the ancient parent rocks that have yet to weather away to individual mineral grains. It could be any fine-grained or coarse-grained igneous, metamorphic or sedimentary rock (Boggs, 2009).

4.3.1.3 Sandstone classification

The sandstones can broadly be divided into two groups: siliciclastic (mainly of terrigenous origin) and nonsiliciclastic (mainly carbonates and evaporates). The present research deals with the siliciclastic sandstones of Bengal Basin. As noted above, the framework grains of the studied sandstones are dominated by quartz, feldspar and rock fragments (labile lithic gains).

193

Photomicrograph 4.3.1.2. (A) The brownish coarse mica biotite (Bi) which is bended (compaction effect) because of diagenesis and altered (transformation) to greenish clay chlorite (Ch). Quartz overgrowth (QO) (cementation) is also shown, depth 3265m at Fenchuganj well-2 (FN2ST20). (B) Moderate stage diagenetic components quartz overgrowth (QO) and suture contact (SC) associated with volcanic lithic grain (Lv), depth 3404m at Shahbazpur well-1 (SB1ST19). (C) Framework grain metamorphic rock fragment schist or mica schist (Lm), sedimentary rock fragment shale or siltstone (Ls) and chert (Ct) in association with diagenetic constituent quartz overgrowth (QO) and dark brownish blocky Fe-carbonate (Fe-C) cement, depth 2757m at Rashidpur well-4 (RP4ST12). (D) Potash feldspar dissolution (Diss) creates secondary porosity (SP) which enhanced the porosity and permeability, depth 3262m at Kailas Tila well-4 (KT4ST5) (Continued).

194 Photomicrograph 4.3.1.2 (Continued). (E) Corrosion of quartz grain occurred due to digenesis. Brownish coarse mica biotite (Bi) that also altered to dark greenish chlorite (Ch), depth 3380m at Kamta well-1 (KM1ST12). (F) Quartz grains fractured because of compaction effect at moderate stage diagenesis which is also corresponded by suture grain contact (SC) and mica bending, depth 3577m at Begumganj well-1 (BG1ST18).

Some other minerals are also measured in lesser quantities. Accordingly, they are ignored for the classification scheme although there are some difficulties in this type of straightforward classification (Folk, 1980; Friedman and Sanders, 1978; Pettijohn et al.,

1987; Boggs, 2009).

Fig.4.3.1.1 A tri-plot of the modal composition of the studied Surma Group sandstones of the Bengal Basin, Bangladesh. The sandstones place within the sublithic arenite to subfeldspathic arenite class (adopted by Folk, 1980).

There are two types of classification: genetic classification, in which the rocks putatively convey the information about their origin, and descriptive classification, which deals with observable properties of rocks without regard to their origin. Hence, the later descriptive classification scheme established by Folk (1980) is used for the current study. The sublithic arenite to subfeldspathic arenite type sandstone is identified based on the petrographic data obtained from the Surma Group sandstones (Fig.4.3.1.1). Lithic arenite contains less than

90% quartz (including chert and quartzite) and unstable rock fragments in excess of

195 feldspars. On the other hand, lower than 90% quartz and feldspar higher than rock fragments correspond to feldspathic arenite (also known as arkose). Since the content of lithic grains or feldspar is less than 25% together with 75-90% quartz in the studied sandstones, the samples correspond to sublithic arenite to subfeldspathic arenite, respectively followed by Folk (1980). In addition, this interpretation for Surma Group sandstone is also supported early by Imam and Shaw (1985, 1987), Islam (2009, 2010) and

Rahman and McCann (2012).

4.3.1.4 Diagenetic constituents

In the broad sense, diagenesis is the process that modifies the sediment after its deposition.

The petrographic study of any sandstone normally focuses on the palaeodepositional environment. But recently the postdepositional changes or the diagenesis have become very significant for better understanding the reservoir sandstones, especially when it becomes economically important as a host for oil or gas. Diagenesis plays an important role in the modification and development of reservoir porosity (Bashari, 1998). It may either decrease the porosity as a result of cementation-compaction or increase in porosity owing to solution processes (Folk, 1980; Boggs, 2009). Therefore, to avoid erroneous interpretations or costly errors in economic evaluations, the following diagenetic observations that would have affected the studied siliciclastic sandstones are highlighted.

4.3.1.4.1 Quartz cements

The process of precipitating silica cement in sandstones during diagenesis involves three important factors such as silica sources, timing of cementation and mechanisms of silica precipitation. The most commonly found silica cement is in the form of quartz overgrowth although its content is very low (0.2 to 4.5%) in the studied Tertiary sandstones (Table

196 4.3.1.1). They are identified as the syntaxial overgrowths on preexisting quartz grains which are, in fact, the optical continuity with the detrital quartz nuclei. In many cases, the authigenic quartz overgrowths are easily distinguished due to the outlines ‘dust line’ of the original detrital quartz grains in thin sections. They are identified out by a line of very tiny iron oxide particles, clay particles or bubbles, although in some cases it is not possible to distinguish with a standard petrographic microscope (Photomicrographs 4.3.1.1B; 4.3.1.2A;

4.3.1.2.B and 4.3.1.2C). SEM is very useful to characterize these overgrowth features. It is found as euhedral crystal faces in partially filled cavities or irregular overgrowth boundaries in filled cavities (Photomicrograph 4.3.1.3A). The local occurrence of pyramid shaped quartz overgrowth is recognized under SEM or FESEM and it occupies the open spaces (Al-Gailani and Ala, 1984). SEM study reveals that, in some cases due to the barrier of chlorite rim, the incomplete development of quartz overgrowth is also observed. The quartz overgrowth sometimes encloses the pore throats between the detrital grains which ultimately reduces the reservoir porosity (Photomicrograph 4.3.1.3B).

4.3.1.4.2 Clay mineral authigenesis

Authigenic minerals are formed in place within sediments either shortly after deposition or during burial and diagenesis. These minerals can occur as cements or crystallize in pore space as new minerals that do not act as cements or form by replacement of original detrital grains. However, the diagenetic changes that affect clay minerals include alteration of nonclay-mineral precursor minerals; comprising the transformation of feldspars and volcanic glass to produce clay minerals, alteration of one kind of clay minerals to another and precipitation of clay minerals into pore spaces where no obvious precursor mineral is present (Boggs, 2009).

197

Photomicrograph 4.3.1.3. (A) Pore-lining authigenic quartz overgrowths (QO) show irregular boundaries partially filled the cavities, depth 2699m at Titas well-11 (T11ST23). (B) Pore- filling pyramidal shaped quartz overgrowths associated with chlorite (Ch) stack, depth 3409m at Shahbazpur well-1 (SB1ST22). (C) Clusters of pore-filling euhedral and pseudohexagonal chlorite crystals associated with quartz overgrowth and smectite (Sm), depth 3578m at Begumganj well-1 (BG1ST19). (D) Pore-filling and pore-bridging euhedral chlorite platelets which dramatically reduced the permeability, depth 3380m at Kamta well-1 (KM1ST12). (E) Frequently found mixed layer chlorite and webby smectite, depth 3620m at Fenchuganj well-2 (FN2ST21). (F) The filamentous illite (I) coating the detrital grain surfaces associated with crenulated morphology smectite, depth 3119.3m at Kailas Tila well-4 (KT4ST3). Quartz overgrowths and smectite-chlorite are formed during intermediate stage of diagenesis.

198 The most important clay cement identified in the analyzed Surma Group sandstone samples is chlorite, ranging from trace to 5.3%. XRD results show the highest relative abundance of chlorite compared to other related clay minerals in the studied samples (Figs.4.3.1.2A and

4.3.1.2B). In thin section, the authigenic chlorite cement forms thin and uniform green rims around the detrital grains (Photomicrograph 4.3.1.1F). Under the SEM, the chlorite is identified by the typical euhedral and pseudohexagonal crystals or platelets that are arranged in different forms and pattern such as rosette pattern, fan shaped, cluster pattern and face-to-face stacked pattern (Photomicrographs 4.3.1.3C and 4.3.1.3D). It is found either as individual crystal or composite crystal or mixed layer clay partly filling the pores in the studied sandstones (Photomicrograph 4.3.1.3E). Other important observed authigenic clay minerals include illite, smectite, kaolinite and mixed layer illite-smectite.

In the Surma Group sandstone samples, the illite is characterized by its filamentous habit under SEM (Photomicrograph 4.3.1.3F). But it looks brownish in thin section which, in sometimes, makes thin ‘dust line’ separating the detrital quartz grain from its authigenic growths. It is found as pore-lining as well as pore-bridging which could act as permeability barriers for fluid (especially hydrocarbons) movement. Sometimes the thin ribbons form a mat-like feature lining the pore coating the detrital grain surfaces (Photomicrograph

4.3.1.4A). Even the development of illite helps to preserve porosity by covering potential quartz nucleation sites, thus inhibiting quartz growth and cementation.

Smectite is distinguished by the highly crenulated, thin, webby and flaky morphology partly coating the detrital quartz grains (Photomicrograph 4.3.1.4B). In few specimens, the chlorite-smectite mixed with blocky kaolinite books is also observed in the samples under

SEM (Photomicrograph 4.3.1.4C).

199 The mixed layer clay of filamentous illite and webby smectite is fairly common in the samples analyzed. The pore-bridging smectite is rarely found in the studied samples

(Photomicrograph 4.3.1.4D).

In thin section, dark brown patches of kaolinite partly filling the pores between detrital quartz and carbonate grains are identified in the samples. It occurs as face-to-face stacks of pseudohexagonal plates or books (typical morphology) partly filling the pore spaces under

SEM (Photomicrographs 4.3.1.4E and 4.3.1.4F). Locally developed vermicular kaolinite is also found the samples.

4.3.1.4.3 Carbonate cements

Both precipitation and dissolution of carbonate minerals can take place during diagenesis until the chemical equilibrium is established. The carbonate cements identified in the analyzed samples are both ferroan calcite (siderite) and nonferroan pure calcite together with some dolomite that range from trace to 9.8% are observed in the samples as well. The

Fe-calcite is also identified by its blocky habits under SEM (Photomicrograph 4.3.1.5B).

The considerable presence of blocky carbonate cements significantly reduce the porosity of the reservoir sandstones analyzed.

4.3.1.4.4 Feldspar authigenesis

A small amount of feldspar overgrowth is seen in the studied samples. The overgrowths are identified either as rimmed K-feldspar authigenesis over the original plagioclase detrital grains or as blocky euhedral to irregular faced K-feldspar over the original clean detrital plagioclases (Photomicrographs 4.3.1.5C and 4.3.1.5D).

200

Fig.4.3.1.2. XRD analysis of clay minerals identified in the analyzed reservoir sandstones and interlayered shales. (A) Non-treated air-dried diffractogram of sandstone samples. (B) Glycol saturated diffractogram of sandstone samples. It shows relative high abundance of clay mineral chlorite compared to others. Both air-dried and glycol-treated diffractograms show the similar responses due to the absence of smectite swelling clay. (C) 550 °C heated diffractogram of sandstone sample and hence the kaolinite peak is disappeared remained a small peak for chlorite. (D) Non-treated air-dried diffractogram of the interlayered shale sample is also shown which indicates the similar clay responses compared to those found in sandstone sample (A and B). It suggests the similar genetic origin for the clay minerals found both in sandstones and shales (e.g., Moore and Reynolds, 1979).

201

Photomicrograph 4.3.1.4. (A) The illite (I) thin ribbons formed a mat-like feature lining the pore coating the detrital grain surface. Pore-bridging illite is also shown and it reduced the porosity-permeability, depth 3377m at Kamta well-1 (KM1ST10). (B) Typical webby and crenulated morphology smectite (Sm), depth 3404m at Shahbazpur well-1 (SB1ST19). (C) Mixed layer webby smectite and euhedral pseudohexagonal chlorite (Ch), depth 2752m at Rashidpur well- (RP4ST11). (D) Pore-bridging smectite that reduced the porosity and permeability, depth 3578m at Begumganj well-1 (BG1ST19). (E) and (F) Kaolinite books (face- to-face stacks of pseudohexagonal plates) partly occluded the pore throats. It is altered from detrital feldspars during early diagenetic stage, depth 2398.5m at Kailas Tila well-5 (KT5ST6).

202

Photomicrograph 4.3.1.5. (A) Rhombic morphology dolomite surrounded by other detrital grains, depth 2840m at Kamta well-1 (KM1ST2). (B) A mosaic of blocky habit Fe-calcites precipitated in pores associated with filamentous illite which occluded the pores, depth 2757m at Rashidpur well-4 (RP4ST12). (C) K-feldspar overgrowth (FO) developed on the original clean detrital plagioclases, depth 3136.5m at Kailas Tila well-4 (KT4ST1). (D) Rimmed K-feldspar authigenesis (FO) over the original plagioclase feldspars. Dissolution (Diss) resulted the secondary porosity during diagenesis, depth 2784m at Titas well-11 (T11ST27).

Dolomite is found in the samples as clusters of small rhombic crystals under SEM

(Photomicrograph 4.3.1.5A). The Fe-calcite (and pure calcite) cement is recognized easily by pore filling mosaic of fine crystals (blocky habit), although single large crystals are not uncommon in the analyzed thin sections (Photomicrograph 4.3.1.2C). The distribution is rather patchy and displacive locally, although some uniform pore filling large area is also

203 covered occasionally by calcite cement. This single crystal is even so large to surround the detrital grain producing the poikilotopic texture.

4.3.1.4.5 Dissolution and replacement

The replacement involves dissolution of one mineral and essentially simultaneous precipitation of another mineral in its place. It occurs as a partial or complete dissolution- replacement event in the samples analyzed (Photomicrograph 4.3.1.2D). Several kinds of minerals are observed as dissolved and, subsequently, either partially or fully replaced in the analyzed siliciclastic sandstones. The most commonly found are albitization whereby the albite plagioclase replaces the K-feldspar or calcic plagioclase types and chloritization where the chlorite replaces the biotite (Photomicrograph 4.3.1.1F). The replacement of clay matrix by carbonate minerals is also identified. Even the dissolution of detrital quartz as a result of corrosion is recognized in few cases under the microscope (Photomicrograph

4.3.1.2E).

4.3.1.5 Compaction and grain packing

Compaction is the decrease of sediment volume and concomitant shrinking of porosity as a result of grain rearrangement and other processes caused by sediment load and tectonic forces. The compaction signatures of diagenesis of the investigated samples are recognized by the estimation of grain packing, ductile grains, primary porosity and grain fractures. The grain packing, in turn, involves the presence of various grain contacts and grain deformation. The five different types of grain contacts defined by Taylor (1950) such as floating, tangential (point-point), long (straight), concavo-convex (embayed) and sutured

(serrated) are observed in the studied siliciclastic sandstone thin sections (Photomicrograph

4.3.1.1C and 4.3.1.2.F). The floating and tangential contacts are less common than

204 concavo-convex and suture contacts. Nonetheless, the bending of flexible grains such as mica flakes, deformation of ductile grains and the fractured grains are the visual evidence of the compaction (Photomicrograph 4.3.1.2.F).

4.3.1.6 Discussion and reservoir implications

Cementation involves the reduction of reservoir porosity and permeability. It was already stated that the development of silica cement (quartz overgrowth) during diagenesis is a function of the silica source, timing and mechanisms. The multiple source of quartz is explained by many workers (Folk, 1980; Boggs, 2009). Pressure solution of quartz grains at points of contact and various mineral reactions that release silica appear to be the most reasonable source of silica cement (quartz overgrowth) in the analyzed siliciclastic sandstones at intermediate and deeper depths (Boggs, 2009). The major phase of quartz cementation (overgrowth) in the studied samples most likely occurs at temperatures of 50-

75 ºC at shallow burial depths as noted by Blatt (1979) and Dutton and Diggs (1990).

Minor quartz cementation would also continue to greater depths and a temperature of 200

ºC. Following the model proposed by Leder and Park (1986), the most probable mechanism of quartz cementation in the sandstones involves with the basin-wide circulation of silica- supersaturated fluids driven by thermal convection or hydrostatic head. Cooling of pore waters offers another reasonable explanation for late-stage quartz cementation locally at moderate depths. The observed straight and long contacts of individual quartz grains correspond to the early stage of diagenesis whereas the concavo-convex and suture contacts represent comparatively later stage of diagenesis (Estupiñan et al., 2010).

Clay mineral diagenesis is influenced by temperature and chemical reactions that affect the composition of the pore-water (Pittman, 1979). It is also associated with a time factor, for

205 example, the chlorite and illite are statistically increased with time (Garrels and Mackenzie,

1971; Blatt et al., 1980). This interpretation is supported by the comparative higher presence of chlorite and illite in the studied siliciclastic sandstones (Figs.4.3.1.2A, 4.3.1.2B and 4.3.1.2C). In fact, a range of diagenetic stages is suggested in the analyzed sandstones.

For example, the presence of kaolinite (feldspar transformation) corresponds to the early stage of diagenesis whereby the smectite-chlorite (clay transformation) represents the moderate stage of diagenesis (SEM Photomicrographs) (Bjorlykke, 1983; Lee et al., 1989).

The identified kaolinite is possibly formed from the feldspar transformation since it is found mostly overlying the feldspar grains under SEM. The chlorite could be of a number of origins (Worden and Morad, 2009; Al-Juboury et al., 2010), but in the analyzed sandstone the most possible mechanism of chlorite precipitation is either the direct replacement from detrital biotite or precursor clay transformation (from smectite to chlorite) or direct precipitation from pore water (Zhang et al., 2012). The chlorite is frequently found in association with altered biotite (Farhaduzzaman et al., 2013k). The similar clay mineral composition (chlorite-smectite-illite) is also found in the interlayered shale lamina which is considered as the major source of clay minerals in the studied sandstones (Figs.4.3.1.2A and 4.3.1.2D). The overall peak intensity in shale samples is comparatively higher than those in sandstone samples. It occurs possibly because of the relative higher concentration of those clay minerals in interlayered shales than those in reservoir sandstones. The pore-lining chlorite (SEM) acts as the barrier of local development of quartz cement which preserves the porosity and permeability. It is encouraging for petroleum geologists affecting positively on hydrocarbons flow (Al-

Ramadan et al., 2004; Rahman and McCann, 2012). The identified dominant illite-smectite mixed layer clay would generate at comparatively intermediate diagenetic stage

(mesogenesis) at temperature of 100-200 ºC whereby the dominant smectite is at 55-100 ºC

206 (Bjorlykke, 1983; Lee et al., 1989). This mixed diagenetic stage is also consistent with the interpretation based on silica cement (quartz overgrowth).

The range of the diagenetic regime is reflected by the presence of microcrystalline to coarse crystalline, patchy to blocky, isolated stringers of carbonate cements in the pores. The observed patchy distribution of the calcite cement reflects initial partial removal of more evenly distributed cement at the early stage of diagenesis subsequently followed by complete carbonate precipitation during comparatively later stage of diagenesis and burial

(Photomicrographs 4.3.1.2C, 4.3.1.5C and 4.3.1.5D). In cementation process, the bicarbonate ions are supplied by organic matter reactions. A source of calcium must also be available to form calcite cements. Dolomite precipitation further requires a source of magnesium and on iron source is essential for Fe-calcite (siderite and ankerite) cements.

Many authors stated that a steady contribution of both cations and anions must be continued in pore water for carbonate cementation (Berner, 1980; Morad et al., 1990, Boggs, 2009).

In the studied Surma Group sandstone samples, it is possible that the mixing of marine- nonmarine sources (with parallel oxidation and sulfate reduction) contributes to carbonate cementation at the early stage of diagenesis (Curtis and Coleman, 1986). The dissolution of skeletal grains of the sandstones furnishes the bicarbonate, calcium and magnesium ions in the pore water. The organic matter fermentation (methanogenesis) and sulfate reduction would also contribute to these ions. The additional Fe, Ca and Mg are supplied from the dissolution of ferromagnesian minerals, calcium feldspar and smectite. This hypothesis is also applicable for organic rich shales interbedded with the studied sandstones and, in fact, it is more appropriate for the succession consisting of alternating sandstone and shale like the currently studied group (Morad et al., 1990). They proposed that the temperature of

120-160 ºC is suitable for Fe-carbonate cementation, however, if the sources are available.

207 Using oxygen isotope study Rahman and McCann (2012) suggested this type of mixing source (nonmarine-marine) for carbonate cementation in the same succession. However

Imam and Shaw (1985) and Islam (2009) emphasized on the skeletal dissolution for carbonate cements in the sandstones.

The decementation and destruction of framework grains increases the porosity as a result of the development of secondary porosity in the analyzed Surma Group sandstones

(Photomicrographs 4.3.1.2D and 4.3.1.5D) (Folk, 1980; Reed et al., 1993; Boggs, 2009).

Moreover, it is not always the true case as a result of the incongruent dissolution whereby the K-feldspar is replaced by kaolinite (kaolinization) with little and no increase in porosity.

The reprecipitated silica overgrowth as a result of pressure solution reduces the porosity.

The replacement process, like dissolution, affects the porosity evolution of the studied sandstones during diagenesis. The principal causes include alteration of feldspar

(albitization and kaolinization) and micas to clay minerals (chloritization) with concomitant increase in volume (Photomicrograph 4.3.1.1F). It appears to plug the pore space which ultimately reduces its porosity and permeability. In addition, the complete dissolution- replacement of framework grains also provides the misleading interpretation of the provenance analysis (although currently it is not discussed in detail) (Morad and Aldahan,

1987).

Wolf and Chilingarian (1976) stated that the compatibility of sandstone is a function of grain size, sorting, shape, orientation, composition, matrix content and cements. As a result of grain rearrangements, the mechanical compaction considered to be the dominant process in the initial stage of diagenesis up to 1.5 km in the studied siliciclastic sandstones. It is

208 determined by the presence of long contacts (Photomicrograph 4.3.1.1F). Subsequently, in deeper part and at the later stage, the diagenesis is dominated by chemical compaction while the additional mechanical compaction is indicated by mica bending, fractured quartz and concavo-convex and suture contacts (Photomicrograph 4.3.1.2A) (Schmidt and

McDonald, 1979). At the intermediate stage of diagenesis; the chemical compaction is marked by dissolution and replacement (Photomicrograph 4.3.1.2D). The well sorted sandstone samples look less compacted while diagenesis followed by less porosity reduction than those with moderately sorted samples followed by greater porosity reduction

(Houseknecht, 1987). The observed long and concavo-convex contacts would develop either during diagenesis (as a result of deformation or solution) or deposition (dependent on grain shapes). The suture contacts are thought to have been generated as a result of dissolution (pressure solution) during comparatively later stage of diagenesis in the sandstones (Taylor, 1950; Hoholick et al., 1982). A summary of digenetic events and their respective comparative stages are shown in Fig.4.3.1.3.

4.3.1.6.1 Implications to reservoir porosity and permeability

Porosity in sandstones is the aggregate total of all the openings or interstices in a rock framework and within grains. It could be either primary porosity that is created during deposition or secondary porosity that is formed during diagenesis (Worden and Burley,

2003). In the petroleum aspect, the interconnected pores (effective porosity) is the most important element for reservoir evaluation. The permeability of any sandstone is its property to permit the passage of fluids (e.g., petroleum) through these interconnected pores. Both porosity and permeability are the controlling parameters for the movement of petroleum in the reservoir.

209

Fig.4.3.1.3. Paragenetic sequence of the important diagenetic events observed in the studied Surma Group sandstone reservoirs, the Bengal Basin, Bangladesh.

The measured total thin section porosity of the studied Surma Group siliciclastic sandstones ranges from 10 to 23% with an average of 18% and it is mostly primary porosity developed during its deposition. The well connected pores (permeable), including intergranular porosity (dominant) and solution porosity, are observed in many of the analyzed samples.

Imam (2005), Islam (2009) and Rahman and McCann (2012) measured the average porosity of the Surma Group sandstone as 18-20%. The porosity values calculated for the current investigation is very consistent with the earlier interpretations. In the present analysis, comparatively less sorted samples show lower porosity (e.g., RP4ST12 = 12%) than that found in well sorted samples (e.g., T11ST27= 20%). Similarly relatively deeper samples show lower porosity value (e.g., BG1ST8= 14%) than that measured in shallower samples (e.g., T11ST27= 20%), although it is always not true in the analyzed samples.

210 Hence, the mechanical compaction (as a result of sediment load) is the controlling factor affecting the porosities of the samples with burial depth and time. Grain rearrangement and reorientation significantly reduces the primary porosity in the sandstones. The overall porosity of the investigated Tertiary sandstones samples decreased with depth (Fig.4.3.1.4).

At deeper depths, few samples shows high porosity compared to relatively shallower samples. Porosity occurs due to the development of secondary porosity (e.g. dissolution) during intermediate diagenetic stage. Nonetheless, at shallow depths, few samples show low porosity compared to deeper samples (Fig.4.3.1.4). The early diagenetic constituents

(e.g., patchy carbonate cements) is considered for this porosity reduction at these shallow depths. The cementation plays important role here to reduce the porosity and permeability in the sandstones analyzed. The pore-filling blocky Fe-calcite cement, pore lining authigenic clays (chlorite-illite-smectite) and quartz overgrowths decreases the porosity and permeability. In very few cases, the pore-bridging mixed layer clay (illite-smectite) plays the most significant role to deteriorate its reservoir quality through the reduction of permeability (SEM photomicrographs). The reservoir permeability is not significantly affected by the diagenetic constituents.

Fig.4.3.1.4. A cross-plot of porosity and depth observed in the Tertiary reservoir sandstones of the Bengal Basin, Bangladesh. It shows the overall porosity decreases with depth.

211 The secondary porosity observed in the studied samples developed because of the dissolution of carbonate cements, feldspars and other unstable constituents during diagenesis (Photomicrographs 4.3.1.2D and 4.3.1.5D). It increases the total porosity of the reservoir sandstone although its amount is not too high compared to the primary porosity.

This type of secondary porosity is observed mostly in moderate to deeper parts of the reservoir. Nevertheless, the dissolution followed by subsequent replacement again reduces its porosity. The quantitative measurement of permeability was not carried out in the present petrographic study, but it is measured in petrophysical study chapter (4.3.2).

Permeability was measured for the Surma Group sandstone by a few workers, for example,

100-400 millidarcy by Imam (2005). On the basis of discussion above, the analyzed sandstone can be ranked as good to excellent petroleum reservoir which is also supported by Imam and Hussain (2002), Islam (2009) and Rahman and McCann (2012).

212 Chapter 4.3.2 Petrophysical Study of the Well Rashidpur 4

Petrophysical log interpretation is one of the most useful and important tools to characterize the reservoir properties (Asquith and Gibson, 1982). Petrophysical study involves the analysis of different parameters of reservoirs including lithology, volume of shale, porosity, water saturation, hydrocarbon saturation, permeability, hydrocarbon moveability and pore geometry by using appropriate well log data. It provides the unique opportunity to observe the relationship between porosity and saturation (Sakurai et al., 2002). Reliable evaluation of hydrocarbon resources in shaly clastic reservoir rocks is an important task. The determination of reservoir quality and formation evaluation processes largely depends on quantitative evaluation of petrophysical properties. Nawab and Islam (2005) estimated shale volume in the Miocene succession for selected gas fields of Bangladesh using gamma ray and porosity logs. But in Bangladesh, the petrophysical analysis concerning shaly sandstone has been performed in limited extent, for example, Islam et al. (2006, 2007 and

2009) and Islam (2010). In this regard, this study attempts to analyze the petrophysical properties of shaly sand gas reservoir encountered in the well Rashidpur 4 (RP4) of

Rasidpur Gas Field, the Bengal Basin, Bangladesh. The Neogene sandstones in the studied well were also analyzed.

4.3.2.1 Data analysis and interpretation

Well log data helps to identify permeable zones; productive zones for hydrocarbon with depth and thickness; and the interfaces of oil, gas or water of a particular reservoir.

Permeable zones may contain either hydrocarbons or water or both. The permeable zones have been identified with the help of GR, SP, resistivity, neutron, density and sonic log responses. Permeable beds are delineated by SP deflection from shale base line. Very low

213 gamma value and low caliper readings in uncaved borehole condition confirm the permeable zones. High resistivity value also indicates permeable zones. Hydrocarbons do not conduct electrical current but saline water highly conducts electrical current. Naturally water bearing permeable zones show low resistivity values compared to hydrocarbon bearing zones. On the other hand, high SP value and low gamma value suggests hydrocarbon bearing permeable zones (Asquith and Gibson, 1982). Very low bulk density and neutron porosity compared to water bearing sandstone and a negative separation between density and neutron responses are also the indicators of hydrocarbon bearing zones

(Fertl, 1987). In this study, 20 permeable zones have been identified from the composite log analysis of 1464 m (1310-2774 m) thickness of the well RP4. Among these permeable zones, four zones have been identified as hydrocarbon bearing and the remaining are water bearing (Table 4.3.2.1).

4.3.2.2 Identification of hydrocarbon bearing zones

Hydrocarbon bearing zones can be identified with the combined use of GR, SP, resistivity

(RILD and RSFL), neutron, density and sonic log responses. In identified hydrocarbon bearing zones, gamma ray log shows low response and SP log shows high value and it deflects from the shale base line (Figs. 4.3.2.1, 4.3.2.3, 4.3.2.5 and 4.3.2.7). For this purpose, resistivity logs are the best option to detect hydrocarbon bearing zones. The resistivity log response in the hydrocarbon bearing zones is very high. Normally, in hydrocarbon bearing zones deep resistivity log (RILD) value is higher than the shallow resistivity log (MSFL). High deflection of neutron and density log with sharp decrease of porosity and density indicate gaseous hydrocarbon. In all of the identified four hydrocarbon bearing zones, some shales are interbedded with the reservoir sandstone, affecting the

214 reservoir properties. The log depth of 1310-2774m is analyzed for the present study.

However, the depth range of 1447-2731 m covers the identified four hydrocarbon bearing zones (cumulative thickness 168 m) in the Miocene sandstone reservoir of the well RP4.

4.3.2.3 Shale distribution

Generally, shale evaluation includes the determination of shale parameters as well as its volume and types. The determination of shale parameters often depends on the experience of log analyst since these parameters vary with different geological factors.

215 Volume of shale in the hydrocarbon bearing zones of the reservoir sandstones of the studied well has been calculated using Schlumberger (1975) and Dresser Atlas (1979) formulas.

The average shale volume of the identified hydrocarbon bearing zones of the well RP4 is

20% (Table 4.3.2.2). Zone 3 contains the lowest and Zone 1 contains the highest volume of shale. Waxman and Smits (1968) suggested that CEC value > 0.2 indicate smectite or illite, whereas CEC value < 0.2 indicates kaolinite or chlorite. In the present study, CEC values are found ≈ 0.2 which indicates mixed types of clay (i.e., chlorite, illite and kaolinite) throughout the Surma Group reservoir intervals of the Bengal Basin, Bangladesh.

4.3.2.4 Porosity ( ) distribution

Porosity of rock is a fraction of void space compared to its total volume. The determination of porosity is a very important step for calculating fluid saturation in reservoir evaluation

(Ruhovets, 1990). Neutron and density logs have been used to calculate porosity distribution for the current study. The porosity values of the individual zone are graphically represented in Figs. 4.3.2.2, 4.3.2.4, 4.3.2.6 and 4.3.2.8. The estimated porosity of the hydrocarbon zones of the Neogene sequence ranges from 7% to 36%, with an average porosity of 21% (Table 4.3.2.2). The calculated porosity data is independent without having any control by any other means.

4.3.2.5 Water saturation (Sw) distribution

Water saturation of the currently investigated hydrocarbon bearing zones in the studied well has not been used for Archie’s (1942) formula. Because this formula is valid for clean sandstone and the values are grately affected by incursion of shale and porosity.

216 Therefore, three most popular formula have been used those were proposed by Simandoux (1963), Fertl (1975) and Schlumberger (1975).

The calculated values of water saturation using these formulas are graphically represented in Figs. 4.3.2.2, 4.3.2.4, 4.3.2.6 and 4.3.2.8.

Finally, the average value of the water saturation calculated from these three different formulas have been considered for further calculation.

The calculated average water saturation values of the four hydrocarbon bearing zones 1-4 in the well RP4 are 20%, 35%, 39% and 14%

(Table 4.3.2.2).

217

Gamma Log (API) SP Log (millivolt) Resistivity (ohm-m) Density (RHOB) Neutron Log (NPHI) 0 50 100 150 -40 -30 -20 -10 0 0 50 100 150 2.1 2.2 2.3 2.4 2.5 2.6 0 0.1 0.2 0.3 0.4 0.5 1435 1435

1445 1445

1455 1455

1465 1465

1475 1475

Zone Zone 1 RILD

Gas MSFL 1485 1485

1495 1495

1505 1505

1515 1515

1525 1525

Fig.4.3.2.1. Composite log responses of the hydrocarbon bearing Zone 1 (1447-1522 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

218

Volume of shale (%) Porosity (%) Water saturation (%) HC saturation (%) Permeability (mD) 0 50 100 0 10 20 30 0 20 40 60 80 100 0 50 100 0 200 400 600 1435 m

1445

1455

1465

1475 Sch Sch Wy Ftl Ftl Ct Smd Smd Avrg

1485 Avrg Avrg

Zone Zone 1 Gas 1495

1505

1515

1525

Fig.4.3.2.2. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing Zone 1 (1447-1522 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

219

GR Log (API) SP Log (millivolt) Resistivity Log (ohm-m) Density Log (RHOB) Neutron Log (NPHI) 0 50 100 150 -95 -75 -55 -35 -15 5 0 20 40 60 2.10 2.20 2.30 2.40 2.50 2.60 0.00 0.10 0.20 0.30 2320

2325

2330

2335

RILD

2340 MSFL Zone Zone 2

2345 Gas

2350

2355

2360

Fig.4.3.2.3. Composite log responses of the hydrocarbon bearing Zone 2 (2337-2350 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

220

Volume of shale (%) Porosity (%) Water saturation (%) HC saturation (%) Permeability (mD) 0 20 40 60 80 100 0 5 10 15 20 25 0 50 100 150 0 20 40 60 80 100 0 50 100 150 2320 m

2325

2330

2335

Sch Sch Wy Ftl Ftl Ct 2340 Smd Smd Avrg Avrg Avrg

2345

Zone Zone 2 Gas

2350

2355

2360

Fig.4.3.2.4. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing Zone 2 (2337-2350 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

221

GR Log (API) SP Log (millivolt) Resistivity (ohm-m) Density Log (RHOB) Neutron Log (NPHI) 0 50 100 150 -100 -80 -60 -40 -20 0 20 0 5 10 15 20 2.2 2.3 2.4 2.5 2.6 0 0.1 0.2 0.3 0.4 2460 m

2465

2470

RILD 2475

MSFL

Zone Zone 3 Gas

2480

2485

2490

Fig.4.3.2.5. Composite log responses of the hydrocarbon bearing Zone 3 (2466-2483 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

222

Volume of shale (%) Porosity (%) Water saturation (%) HC saturation (%) Permeability (mD) 0 50 100 0 10 20 30 0 50 100 0 20 40 60 80 0 50 100 150 200 2460 m

2465

2470

Sch Sch Wy Ftl Ftl 2475 Ct Smd Smd Avrg

Avrg Avrg Zone Zone 3

2480 Gas

2485

2490

Fig.4.3.2.6. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing Zone 3 (2466-2483 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

223

GR Log (API) SP Log (millivolt) Resistivity (ohm-m) Density (RHOB) Neutron Log (NPHI) 0 50 100 150 -80 -60 -40 -20 0 0 50 100 150 200 1 1.5 2 2.5 3 0.2 0.3 0.4 0.5 2660 m

2670

2680

2690

Zone Zone 4 Gas 2700 RILD MSFL

2710

2720

2730

2740

2750

Fig.4.3.2.7. Composite log responses of the hydrocarbon bearing Zone 4 (2668-2731 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

224

Volume of shale (%) Porosity (%) Water saturation (%) HC saturation (%) Permeability (mD) 0 20 40 60 80 100 0 10 20 30 40 0 50 100 0 50 100 0 500 1000 2660 m

2670

2680

2690 Zone Zone 4 2700 Sch Sch Wy Gas Ftl Ftl Ct Smd Smd Avrg Avrg Avrg 2710

2720

2730

2740

2750

Fig.4.3.2.8. Graphical presentation of the petrophysical parameters of the hydrocarbon bearing Zone 4 (2668-2731 m) identified in Surma Group of well Rashidpur 4, the Bengal Basin, Bangladesh.

225 4.3.2.6 Hydrocarbon saturation (Sh) distribution

Hydrocarbon saturation of a reservoir is determined by subtracting water saturation from the value of total saturation which is 1 (one). The permeable zone having more than 60% hydrocarbon saturation (Sh) value is commonly treated as a hydrocarbon bearing zone

(Asquith and Gibson, 1982). Following all three commonly used formulas, Sh values of all hydrocarbon bearing zones are greater than 60% (Figs. 4.3.2.2, 4.3.2.4, 4.3.2.6 and 4.3.2.8).

Sometimes, the presence of shale in the Miocene reservoir sandstones decreases the content of Sh. In case of water saturation calculation, Schlumberger’s (1975) formula has been found better suited among these three formulas (c.f., Islam et al., 2006 and 2013; Islam,

2010). The calculated average values of hydrocarbon saturation of the zones 1-4 of the studied well RP4 are 80%, 65%, 61% and 86%. Based on hydrocarbon saturation, the zones can be ranked as Zone 4 > Zone 1> Zone 2> Zone 3.

4.3.2.7 Permeability (K) distribution

Permeability is an indicator of the ability of a rock to transmit fluids. Permeability (K) values of hydrocarbon bearing zones in the studied wells have been calculated using Coates and Dumanoir (1973) formula. The results are shown in Table 4.3.2.2. The average permeability values of the gas zones 1-4 of the investigated reservoir sandstones are 54, 33,

28 and 305 mD respectively. Considering its average permeability, Zone 4 has the greatest potential. All values calculated here indicate that the identified hydrocarbon bearing zones are commonly good to very good reservoirs according to the generalized observation made by Asquith and Gibson (1982).

226 4.3.2.8 Hydrocarbon moveability index (Sw/Sxo)

Hydrocarbon moveability index is the ratio between water saturation of uninvaded zone

(Sw) to the water saturation of flushed zone (Sxo). If the ratio of Sw and Sxo is ≥1, then the hydrocarbon would not move toward the well bore. If this ratio is less than 0.7 (for sandstone), the hydrocarbon is considered to be moveable (Schlumberger, 1972). From the calculated results (Table 4.3.2.2), it can be inferred that the hydrocarbons of the selected zones in the studied well RP4 are moveable because all movability index values are less than 0.7.

4.3.2.9 Bulk volume of water (BVW)

Bulk volume of water is the product of formation’s water saturation and its porosity. It is important to know BVW whether the formation is at irreducible water saturation or not.

When the value of BVW is constant or close to constant with some minor scattering, it indicates the homogenous formation having as close to irreducible water saturation. If the

BVW ranges from 0.035 to 0.07, the grain size of the rock succession is fine to very fine grained sandstone (Fertl and Vercellino, 1978). The BVW values of the hydrocarbon bearing zones in the studied well have been calculated using Morris and Biggs (1967) formula. The calculated bulk volume of water is nearly constant with some minor scattering in the hydrocarbon bearing zones, indicating that the reservoir rock consists mainly of fine to medium grained sandstone.

4.3.2.10 Discussion

Porosity and permeability are the two most important parameters which can be determined directly or indirectly from well log analysis (Asquith and Gibson, 1982).

227 These characteristics of rock are affected in many ways during logging measurements.

There are many variables and techniques to minimize the adverse down hole effects and drawbacks of some computation procedures. However, none of them is unique. For example, a, m and n are three parameters (constants) termed as the tortuosity, cementation and saturation exponents. These parameters differ from rock to rock and basin to basin. In the Bengal Basin, there are no prescribed values of these parameters. In this study, the values of these parameters have been used in a generalized fashion and considered as 0.62,

2.15 and 2 respectively. These values might also affect the overall calculations. Neutron, density and sonic log readings have been used to determine the porosity. Porosity measurements from density logs require matrix density. Most postulated matrix density for sandstone is 2.7 cc/gm (Schlumberger, 1972). Core derived density values from this study range from 2.1 to 2.6 gm/cc. The constant value of matrix density might also affect the porosity calculation from density log. The computation processes needs some correction due to shale effect on the log data because the studied reservoirs consist of more than 10% shale. If the effects of shale on the porosity measurement are not duly minimized, then the measurement might lead to deviation from the correct values.

There is no known tool that can measure permeability without any error. Core derived permeability is often calculated based on empirical rather than measured studies. Well logs can predict relative indications of permeability, which are usually termed “permeability index” and are qualitative rather than quantitative. The quality of the index hinges on the quality of the data (Brock, 1986). The hardest parameter to pin down is that of the irreducible water saturation (Swirr). Log derived permeability formulas are only valid for estimating permeability in formation with irreducible water saturation (Schlumberger,

1977).

228 The product of water saturation (Sw) and porosity (ø) is known as bulk volume of water

(BVW). If values for BVW across the reservoir interval are constant or very close to constant, then the hydrocarbon production from the reservoir should be water free. Hence, the saturated water in the uninvaded zone will not move due to capillary pressure existing between the sediment grains (Morris and Biggs, 1967). Nevertheless, it is always difficult to find a reservoir at irreducible water saturation state due to heterogeneities in the reservoir properties. The present study also suffers from this difficulty. In the shaly sand calculation, the shale parameters within the reservoir were translated from the neighboring shale zone, which may not be same in all cases.

In this study, petrography (thin section) based average porosity ranges from 17% to 23% having an average value of 19%. On the other hand, log derived average porosity is 7-36%, while the average is 21%. There is a slight increase of porosity values in case of log analysis. Among other core samples, only five selected sandstone samples of RP4 were chosen for petrographic (thin section) analysis. Here, comparatively shale free sandy samples are considered for measurement. Relatively clean sandstone provides high permeability and comparatively high porosity. Due to larger pore radius, core samples exhibit high permeability and porosity; and due to shale effects, log measurements exhibit significant increase in porosity and a decrease in permeability. Four gas zones from the well RP4 consist of 168 m thick gas sands. So huge data points, even from thinly laminated shaly horizons, are accompanied by comparatively less shaly sandy horizon increase the log porosity and decrease the log permeability. The heterogeneity of the studied reservoirs might responsible for down grading the log permeability values.

229 There are many examples from petroleum basins around the world showing that Petroleum reservoir rocks may range from 0.1 to 1000 or more millidarcies (mD). The quality of a reservoir as determined by permeability (in mD) may be judged as poor if K<1, fair if

1250 (Tiab and

Donaldson, 1996). The average permeability measured for the gas zones ranges from 28 to

306 mD. In this regard, permeability values of all reservoir intervals of the well Rashidpur

4 indicate good to very good quality reservoirs (Table 4.3.2.2). Porosity, hydrocarbon saturation and movability index values of the selected hydrocarbon zones of the studied well indicate good to very good reservoir conditions in the Bengal Basin. This interpretation is also supported by Imam (2005), Islam (2009, 2010) and Rahman and

McCann (2012). The identified zone 4 (2668-2731 m) has the best potential as a hydrocarbon bearing zone in terms of its porosity and it is also supported by other parameters such as hydrocarbon saturation and permeability. The studied clays within the reservoir sandstone samples are mixed types (i.e., chlorite, illite and kaolinite) throughout the Surma Group, which is consistent with the interpretation made with the help of XRD and microscopic study (see section 4.3.1). This is also supported by Imam and Shaw

(1987), Islam (2009, 2010) and Rahman and McCann (2012). However, the study assumes that the anomaly in log based measurements may be because of the inherent problems of different formulas, e.g., selection of saturation and permeability formulas and constraints related to values of different constants.

230 CHAPTER 5: CONCLUSIONS AND RECOMMENDATIONS

5.1 Shale

Based on geochemical and petrographical characteristics of the analyzed shale samples the following salient findings are drawn:

 Both Bhuban and Boka Bil shales of Bengal Basin possess poor to fair quality

source potential for hydrocarbon generation. The organic matter, comprising a

mixture of Type III/II kerogens, cross-plots of TOC versus S2, PI versus Tmax and

hydrocarbon yield versus hydrocarbon in extract supports this hydrocarbon

potential. The dominancy of aromatic compounds and n-alkane/alkene doublets in

the PyGC pyrograms agree with each other regarding this poor to fair hydrocarbon

potential of the studied shale samples.

 The examined Bhuban and Boka Bil shale samples were found to be thermally

immature to early mature oil window for hydrocarbon generation based on the mean

vitrinite reflectance and Tmax values. The production index, TAI value and the

biomarker values of 22S / (22S + 22R) hopane, moretane/hopane ratio and sterane

parameters also support this level of thermal maturity.

 The biomarker parameters, such as very low to low Ts/Tm ratio, moderate Pr/Ph

ratio, alternating dominance of odd over even and even over odd homologs in n-

alkanes, high abundance of C29 regular steranes and medium to high C/S ratio,

support the concept that the organic matter of the analyzed shales derived from land

plants of terrestrial environmental settings with minor contribution from marine

231 sources. The depositional condition is considered here an alternation of oxic to

anoxic. The marine influence is detected in the analyzed shale samples by the

presence of liptodetrinite, resinite and other fluorescing amorphous materials under

microscope.

 The present study affirms that the Bhuban and Boka Bil formations exhibit similar

geochemical and petrological characteristic. The similar environmental setting and

depositional condition are also noticed.

5.2 Coal

On the basis of macroscopic, microscopic and organic geochemical study of the Permian coals, the following salient features are stated:

 The coal seams are very thick with a maximum cumulative thickness of 71m. The

nature of coal is dull to banded dull. The coal is low ash, low sulfur, high volatile

bituminous B. It also has coking properties. Chemical composition (especially Cr,

Cd, Pb, Co and Ni) directs the environmental hazards for coal combustion.

 Inertinite is the most dominant maceral group of the analyzed Gondwana coals of

both the Barapukuria and Dighipara basins. Semifusinite, fusinite and inertodetrinite

are the principal macerals of the inertinite group. Vitrinite is the second

predominant group of the studied macerals. Collotelinite, collodetrinite and

vitrodetrinite are the most commonly found vitrinite group maceral in these coals.

232

Sporinite, cutinite and resinite comprises the major constituents of the liptinitic

macerals. Trimacerite (e.g., clarodurite and duroclarite) is identified as the dominant

microlithotype of the investigated coal samples, followed by bimacerite and

monomacerite with considerable carbominerites. Durite, vitrinertite and clarite are

the most common bimaceral microlithotypes in the studied samples. Vitrite and

semifusite are the most dominant monomaceral group.

 The analyzed different facies models suggest mostly the forest swamps with mixed

palaeodepositional conditions. Alternating oxic to anoxic conditions under

terrestrial environments with recurrent flooding were inferred for deposition. The

studied Permian coals evolved in limno-telmatic zones under fluvio-lacustrine

conditions with development of upper delta to lower delta plain conditions close to

fresh water lake areas, as demonstrated by the composition of the microlithotypes in

the models. The cross-plot of TPI versus GI suggests a terrestrial origin with

increased tree density within the depositional system. GWI versus VI cross-plot

implies the herbaceous plant-dominated ombotrophic to mesotrophic

hydrogeological conditions. The pictorial presentation of maceral indices with depth

also supports the fluctuating palaeodepositional environment.

 The organic geochemical and organic petrological approaches applied here are able

to differentiate the organic facies in the analyzed coal, carbargillite and mudstone

samples. The organic facies parameters including high C29/C30, Tm/Ts, CPI values,

sterane/hopane and predominance of aromatic hydrocarbons over aliphatic

233 hydrocarbons are strongly associated with the source facies input. The coals are

dominantly terrestrial with minor contribution from marine influenced sources.

The carbargillites are mixture of terrestrial marine influenced sources and

mudstones being terrestrial with no marine derived organic input. This

interpretation is also supported by the relative proportions of regular steranes, cross-

plot of HI versus Tmax and maceral analysis. Another cross-plot of Pr/nC17 versus

Ph/nC18 indicates the suboxic depositional conditions for the organic matter related

with the studied coal, carbargillite and mudstone samples. These are also supported

by the high Tm/Ts ratios, very high Pr/Ph values and the predominance of inertinite

macerals.

 Fair to excellent hydrocarbon generation potential is estimated for the analyzed

samples. The carbargillites possess reasonably good potential for both oil and gas. It

is followed by coals (mainly gas with minor oil) and mudstones (gas only). The

considerable presence of liptinite macerals (cutinite, liptodetrinite, resinite,

bituminite and sporinite) along with fluorescing vitrinite are believed to play

important roles in hydrocarbon generation. All of the studied samples were found to

be thermally mature. The common presence of exsudatinite, fluorinite, solid

bitumen and micrinite suggests the analyzed coal, carbargillite and mudstone

samples have already expelled hydrocarbons in the associated Gondwana Petroleum

System.

234 5.3 Sandstone

 The principal framework grains identified in the analyzed siliciclastic Surma Group

sandstones include quartz, feldspar and lithic grains. The studied sandstones are

classified as sublithic arenite to subfeldspathic arenite.

 The observed most important diagenetic constituents include quartz cement

(overgrowth), authigenic clays, carbonate cements and dissolution-replacement

together with the compaction. The measured average thin section porosity is 18%

though it is mostly of primary origin. The primary porosity is controlled chiefly by

textural maturity as a function of grain size, sorting and fabric during burial. A

range of diagenetic stages early to intermediate is estimated on the basis of several

distinguishing properties such as compaction effects, alterations, cements and clay

mineral authigenesis.

 The dissolution of unstable grains and cements increases the porosity (secondary).

Thus, it enhances the permeability and reservoir quality. The precipitation of

cements (quartz overgrowth, carbonate, clays) greatly influences the porosity

reduction. SEM revealed that the pore-bridging authigenic constituents (illite-

smectite) tend to plug the pore throats. This can reduce the permeability drastically,

although it is very rare. The pores and its passage throats are distributed more or

less consistently in the samples analyzed. The studied Surma Group sandstone is

characterized as good to excellent petroleum reservoir.

235  Among twenty permeable zones of the well RP4, four potential gas zones were

identified with a gross cumulative thickness is 168 m. The study measured the log

derived petrophysical parameters including shale volume, porosity, water saturation,

hydrocarbon saturation, permeability, moveability index and bulk volume of water.

These are (gross average) 20%, 21%, 27%, 73%, 105mD, 0.2 and 0.06,

respectively. The log derived porosity slightly exceeds thin section porosity. The

study reveals that all of the four gas zones possess good to very good quality

reservoirs in the well Rashidpur 4 of the Bengal Basin, Bangladesh, a conclusion

also supported by the interpretation based on petrography. Nonetheless, zone 4 is

considered the best potential for hydrocarbon generation and production of the well

Rashidpur 4.

5.4 Recommendations for future work

The present research covers some of the important essential petroleum system elements of

Bengal Basin, Bangladesh. The following are recommended for future study.

 Detailed palynological analysis would add the important information on the

palynofacies, biostratigraphy and depositional environments.

 Isotopic (O, H and C) study could supplement the present output on source and

maturity of organic matter.

 A study on source-oil correlation and oil-oil correlation is strongly advised.

 Detail seismic study is recommended for better understanding of the basin as well

as the petroleum reservoir.

236  Samples from the deeper part of the basin could be required to envisage the source

rock coverage with more accuracy. Accordingly, deeper (up to 6 km) drilling is

advised.

 Cathodoluminescence study is required for getting information on fracture network,

polycrystallinity of quartz, grain boundary nature, cements, microstructure, growth

zoning, deformation features, fluid flow, alteration features and diagenetic events as

well.

 Insitu measurements of core porosity and permeability of the reservoir sandstones.

 Usage of different geological software (e.g., PetroMod, BasinMod, IP, Techlog,

Petrel, etc.) for basin modeling, reservoir characterization and petroleum system

analysis for supplementing the current study.

237

APPENDICES

238 International Journal of Coal Geology 90–91 (2012) 162–179

Contents lists available at SciVerse ScienceDirect

International Journal of Coal Geology

journal homepage: www.elsevier.com/locate/ijcoalgeo

Depositional environment and hydrocarbon source potential of the Permian Gondwana coals from the Barapukuria Basin, Northwest Bangladesh

Md. Farhaduzzaman a,⁎, Wan Hasiah Abdullah a,1, Md. Aminul Islam b,2 a Department of Geology, Faculty of Science, University of Malaya, 50603 Kuala Lumpur, Malaysia b Department of Petroleum Geoscience, Faculty of Science, Universiti Brunei Darussalam, Gadong BE1410, Brunei article info abstract

Article history: Barapukuria Coal Basin is situated in Dinajpur district of the northwestern part of Bangladesh. A total of eight Received 20 June 2011 coal samples have been collected from two different locations of the basin and analyzed using organic geo- Received in revised form 10 December 2011 chemical and organic petrological methods. Accepted 15 December 2011 The extracted organic matter of the studied samples is a mixture of Type-III and Type-II kerogen as evaluated Available online 29 December 2011 by the source rock analyzer (SRA) and PyGC pyrograms. The measured total organic carbon (TOC) ranges from 61 to 74 wt. % and the recovered extractable organic matter (EOM) varies from 27,561 to Keywords: Gondwana coal 41,389 ppm. These results suggest that the coals are ranked as good quality source rock. The hydrocarbon Depositional environment yield has been calculated which is also high and it ranges from 12,192 to 20,799 ppm. The organic matter Hydrocarbon potential is thermally mature for hydrocarbon generation considering their Tmax and measured mean vitrinite reﬂec- Biomarker tance values of 431 to 435 °C and 0.72 to 0.81%Ro respectively. The hopane 22S/(22S+22R), moretane/ Thermal maturity hopane ratio and sterane parameters are also in support of these thermal maturity assessment. Kerogen type The maceral composition is dominated by the inertinite group with signiﬁcant amounts of vitrinite and liptinite. The more dominant odd carbon numbered n-alkanes, high Pr/Ph ratio (4–8), high Tm/Ts ratio

(13–18), predominant sterane C29 (i.e., C29 >C28 >C27) and Pr/nC17 – Ph/nC18 values, GI vs TPI cross-plot and dominance of inertinite macerals group clearly demonstrate that the organic matter has been derived from terrestrial inputs and the condition of deposition was oxic (i.e., dry forest swamp) which was also supported by the absence of alginite. It is most likely that the coals were deposited within a peat-swamp ﬂood basin environmental setting. © 2011 Elsevier B.V. All rights reserved.

1. Introduction coals of Barapukuria. Shamsuddin et al. (2001) discussed on the source rock potentiality of Gondwana coals of Bangladesh as a partial The aim of the present study is to interpret the depositional envi- study on Petroleum Systems of Bangladesh. Islam and Kamruzaman ronment of the Permian Gondwana coals of the Barapukuria basin on (2006) studied on inorganic geochemistry and techno-environmental the basis of biomarker distributions together with other organic geo- issues related to mining and uses of Barapukuria coal of Bangladesh. chemical and organic petrological methods. So far no record of work- Islam and Hossain (2006) worked on the lithofacies and Embedded ing detail on depositional environment considering the organic Markov Chain analysis of Gondwana sequence of Barapukuria coal geochemical and organic petrological approach have been published basin, Bangladesh. Farhaduzzaman et al. (2008) published on proper- on the Permian Gondwana coals of Bangladesh although there are ties (e.g., moisture, ash, volatile matter, ﬁxed carbon, caloriﬁcvalue,sul- few publications on Gondwana coals of Bangladesh. Bostick et al. fur, etc.) of Gondwana coals of Bangladesh. Islam and Hayashi (2008) (1991) discussed on petrography of the Barapukuria coal. Akhtar published on geology and coal bed methane resource potential of the and Kosanke (2000) published on Palynology of Permian Gondwana Gondwana Barapukuria coal basin, Dinajpur, Bangladesh. Frielingsdorf et al. (2008) presented a paper on tectonic subsidence modeling and hydrocarbon potential from a structural point of view based on the wells located in the Northwest Bangladesh considering thermal and ⁎ Corresponding author. Tel.: +60 149248160; fax: +60 379675149. maturity modeling. The depositional environment is the focus of the E-mail addresses: [email protected], [email protected] present study emphasizing the biomarker characteristics of the Permian (M. Farhaduzzaman), [email protected] (W.H. Abdullah), coals of Barapukuria and this study will certainly add further important [email protected], [email protected] (M.A. Islam). 1 Tel.: +60 379674232; fax: +60 379675149. information to the understanding of the condition of depositional set- 2 Tel.: +673 2463001x1371; fax: +673 2463051. tings related to the coals of the Bengal basin.

239 Journal of Petroleum Geology, Vol. 35(4), October 2012, pp 357-376 357

SOURCE ROCK POTENTIAL OF ORGANIC-RICH SHALES IN THE TERTIARY BHUBAN AND BOKA BIL FORMATIONS, BENGAL BASIN, BANGLADESH

Md. Farhaduzzaman1*, Wan Hasiah Abdullah1, Md. Aminul Islam2 and M. J. Pearson3

Sandstones in the Miocene Bhuban and Lower Pliocene Boka Bil Formations contain all of the hydrocarbons so far discovered in the Bengal Basin, Bangladesh. Organic-rich shale intervals in these formations have source rock potential and are the focus of the present study which is based on an analysis of 36 core samples from wells in eight gasfields in the eastern Bengal Basin. Kerogen facies and thermal maturity of these shales were studied using standard organic geochemical and organic petrographic techniques. Organic matter is dominated by Type III kerogen with lesser amounts of Type II. TOC is 0.16- 0.90 wt % (Bhuban Formation) and 0.15-0.55 wt % (Boka Bil Formation) and extractable organic matter (EOM) is 132-2814 ppm and 235-1458 ppm, respectively. The hydrogen index is 20-181 mg HC/g TOC in the Bhuban shales and 35-282 mg HC/ g TOC in the Boka Bil shales. Vitrinite was the dominant maceral group observed followed by liptinite and inertinite. Gas chromatographic parameters including the C/S ratio, n-alkane CPI, Pr/Ph ratio, hopane Ts/Tm ratio and sterane distribution suggest that the organic matter in both formations is mainly derived from terrestrial sources deposited in conditions which alternated between oxic and sub-oxic. The geochemical and petrographic results suggest that the shales analysed can be ranked as poor to fair gas-prone source rocks. The maturity of the samples varies, and vitrinite

reflectance ranges from 0.48 to 0.76 %VRr. Geochemical parameters support a maturity range from just pre- oil window to mid- oil window. INTRODUCTION is bordered to the west by the Precambrian Indian shield, to the north by the Shillong Massif and to the The Bengal Basin covers on- and offshore Bangladesh east by the frontal fold-belt of the Indo-Burmese and extends into the Indian states of West Bengal to Range. To the south it extends for some distance into the west and Tripura to the east (Fig.1A). The basin the Bay of Bengal (Fig.1A). The deltas of three major 1 Department of Geology, Faculty of Science, University river systems (Ganges, Brahmaputra (Jamuna) and of Malaya, 50603 Kuala Lumpur, Malaysia. Meghna) pass into the Bengal Fan whose frontal lobes 2 Department of Petroleum Geoscience, Faculty of extend about 3000 km south of the coast line (Curray Science, Universiti Brunei Darussalam, Gadong BE1410, and Moore, 1974). Brunei. 3Department of Geology and Petroleum Geology, University of Aberdeen, King’s College, Aberdeen, AB24 Key words: Bhuban Formation, Boka Bil Formation, 3UE. Miocene, Pliocene, organic petrology, source rocks, *Corresponding author, email: [email protected], thermal maturity, hopane, sterane, Bengal Basin, [email protected] Bangladesh.

240 Journal of Asian Earth Sciences 64 (2013) 272–287

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Journal of Asian Earth Sciences

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Petrographic characteristics and palaeoenvironment of the Permian coal resources of the Barapukuria and Dighipara Basins, Bangladesh ⇑ Md. Farhaduzzaman a, , Wan Hasiah Abdullah a,1, Md. Aminul Islam b,2 a Department of Geology, Faculty of Science, University of Malaya, 50603 Kuala Lumpur, Malaysia b Department of Petroleum Geoscience, Faculty of Science, Universiti Brunei Darussalam, Gadong BE1410, Brunei article info abstract

Article history: Twenty-seven coal samples from the Barapukuria and Dighipara Coal Basins of Bangladesh were analysed Received 24 March 2012 for their maceral content, petrographic characteristics and vitrinite reflectance. The most predominant Received in revised form 13 December 2012 maceral was the inertinite group (mean 40%), followed by vitrinite (mean 31%) and liptinite (mean Accepted 15 December 2012 22%), with considerable amounts of mineral matter (mean 7%). Semifusinite, fusinite and inertodetrinite Available online 5 January 2013 were the most common macerals of the inertinite group. Collotelinite, collodetrinite and vitrodetrinite were the most frequently found macerals of the vitrinite group, while sporinite and cutinite were the Keywords: most common in the liptinite group. Clay minerals occurred in higher concentrations than other minerals. Gondwana coal The measured vitrinite reflectance values (%R ) ranged from 0.71 to 0.80, indicating a high volatile bitu- Macerals o Microlithotypes minous B ranking. Facies model Facies modelling using maceral composition and maceral indices suggested an environment of forest Paleofacies evolution swamps with alternating oxic–anoxic depositional conditions. Microlithotype-dependent depositional Palaeoenvironment modelling indicated evolution in limno-telmatic zones under fluvio-lacustrine control, accompanied by the development of upper to lower deltaic plain conditions. A terrestrial origin with dry forest to piedmont plain conditions was suggested by the Gelification Index (GI) and Tissue Preservation Index (TPI). The lateral variation of the measured TPI values indicated an increase in the rate of basin subsidence. A cross-plot of the Ground Water Index (GWI) vs. the Vegetation Index (VI) suggested mires under ombotrophic to mesotrophic hydrogeological conditions containing herbaceous plants. Ó 2012 Elsevier Ltd. All rights reserved.

1. Introduction No systematic work has as yet been carried out on the Perm- ian Gondwana coals of Bangladesh. Published studies have cov- The Gondwana succession of the Bengal Basin (Bangladesh) is ered: the petrography of the Barapukuria coal using the new very important because of its preserved coal deposits. To date, it analytical technique of reﬂectance scanning (Bostick et al., has been estimated to contain 3 billion tons of coal resources 1991); the palynomorphs of the Permian Gondwana coals of Bar- (Farhaduzzaman et al., 2008). The coal deposits of these two basins apukuria (Akhtar and Kosanke, 2000); the potential source rock occur at shallow depths (Imam, 2005). Petrography is an important of the Gondwana coals of Bangladesh (Shamsuddin et al., method, commonly used to evaluate the facies and palaeoenviron- 2001); a study of the Barapukuria coal, focussing on the geo- mental interpretation, that is used worldwide by numerous chemistry and techno-environmental issues related to mining researchers and for various geological ages (e.g., Amijaya et al., (Islam and Kamruzaman, 2006); an analysis of the lithofacies 2006; Daulay and Cook, 1988; Hower et al., 2008; Jasper et al., and cyclicity of the Gondwana succession of the Barapukuria 2010; Kalkreuth et al., 1999; Querol et al., 2001; Singh and Singh, Basin, Bangladesh (Islam and Hossain, 2006); the methane 2004; Toprak, 2009; Wan Hasiah, 2003; Wan Hasiah and Abolins, resource potential of the coal beds of the Gondwana Barapukuria 1998). Basin, Bangladesh (Islam and Hayashi, 2008); the proximate analysis and coal rank of the Gondwana coals of Bangladesh (Farhaduzzaman et al., 2008); and tectonic subsidence modelling ⇑ Corresponding author. Tel.: +60 149248160; fax: +60 379675149. based on the Gondwana coals from the Kuchma, Singra and Haz- E-mail addresses: [email protected], [email protected] ipur wells of Bangladesh (Frielingsdorf et al., 2008). The present (Md. Farhaduzzaman), [email protected] (W.H. Abdullah), aminul_gm_ru@ paper evaluates the palaeofacies and palaeodepositional environ- yahoo.com, [email protected] (Md.A. Islam). 1 ment on the basis of the petrographic characteristics of the Tel.: +60 379674232; fax: +60 379675149. 2 Tel.: +673 2463001x1371; fax: +673 2463051. Permian coal deposits of Bangladesh.

ORGANIC FACIES VARIATIONS AND HYDROCARBON GENERATION POTENTIAL OF PERMIAN GONDWANA GROUP COALS AND ASSOCIATED SEDIMENTS, BARAPUKURIA AND DIGHIPARA BASINS, NW BANGLADESH

Md. Farhaduzzaman1*, Wan Hasiah Abdullah1, Md. Aminul Islam2 and M. J. Pearson3

In the Barapukuria and Dighipara coal basins, NW Bangladesh, the Basement Complex is overlain by the coal-bearing Permian Gondwana Group. In the present study, 36 core samples collected from five boreholes in these two basins were analysed using organic geochemical and organic petrological methods. Based on the results of biomarker analyses (TIC, m/z 191 and m/z 217 fragmentograms) and maceral composition (proportions of vitrinite, liptinite, inertinite), three organic facies were identified: coals, carbargillites and mudstones. Together with other evidence,

cross-plots of HI versus Tmax and Pr/nC17 versus Ph/nC18 indicate that the coals, as expected, were dominated by terrestrial organic matter (OM). The carbargillites contained a mixture of terrestrial and probable Type II aquatic OM, and the mudstones contained mostly terrestrial OM. Accordingly the coals, carbargillites and mudstones are interpreted to have been deposited in swamp-dominated environments in a delta-plain setting which was subject, in the case of carbargillites, to periodic flooding. Suboxic conditions were indicated by very high Pr/Ph ratios and a high content of inertinite macerals. All the samples analysed were immature or early mature for hydrocarbon generation, as

indicated by mean vitrinite reflectance (%Ro) of 0.60-0.81%, Rock-Eval Tmax of 430-439°C, and biomarker ratios (hopane C32 22S/(22S+22R)) of 0.57-0.60. Carbargillites showed potential for both liquid and gaseous hydrocarbon generation; coals were mainly gas-prone with minor liquid hydrocarbon potential; and mudstones were dominantly gas-prone. The oil-prone nature of the samples was attributed to the presence of resinite, cutinite, bituminite and fluorescent vitrinite. The presence of exsudatinite within crack networks, solid bitumen and oil droplets as well as bituminite at early oil-window maturities suggests that the organic matter may have expelled some hydrocarbons. INTRODUCTION 1 Dept. of Geology, Faculty of Science, University of Malaya, 50603 Kuala Lumpur, Malaysia. In the Bengal Basin, Bangladesh (Fig. 1), all of the 2 Dept. of Petroleum Geoscience, Faculty of Science, Universiti Brunei Darussalam, Gadong BE1410, Brunei. hydrocarbon discoveries so far made (gas = 28.42 3 Dept of Geology and Petroleum Geology, University of TCF GIIP; oil = 137 million barrels STOIIP) are Aberdeen, King’s College, Aberdeen, AB24 3UE. Key words: Coal, carbargillite, mudstone, Barapukuria * Corresponding author, email: Basin, Dighipara Basin, source rocks, Bengal Basin, [email protected]; [email protected] Bangladesh, Permian, Gondwana Group.

242 243 Geosciences Journal

Petrography and diagenesis of the Tertiary Surma Group reservoir sandstones, Bengal Basin, Bangladesh --Manuscript Draft--

Manuscript Number: Full Title: Petrography and diagenesis of the Tertiary Surma Group reservoir sandstones, Bengal Basin, Bangladesh Article Type: Article Corresponding Author: Md. Farhaduzzaman University of Malaya Kuala Lumpur, MALAYSIA Corresponding Author Secondary Information: Corresponding Author's Institution: University of Malaya Corresponding Author's Secondary Institution: First Author: Md. Farhaduzzaman First Author Secondary Information: Order of Authors: Md. Farhaduzzaman Md. Aminul Islam, PhD Wan Hasiah Abdullah, PhD Order of Authors Secondary Information: Abstract: The aim of the present research was to evaluate the petrographic characteristics of the Tertiary Surma Group sandstone reservoirs. The diagenetic constituents, processes and their impacts on reservoir quality were evaluated. A total of 33 core samples collected from 8 different wells located in 7 different gas/oil fields of Bangladesh were used for the current petrographic and diagenetic study. The standard petrographic microscope, scanning electron microscope (SEM/FESEM) and XRD were used in the current study. The framework grains, mineralogy, matrix, pore properties and cements were identified and counted properly. The framework grains were in accordance to dominance quartz (76-91%), rock fragments (5-16%) and feldspar (3-14%). The identified important diagenetic components were quartz cements, authigenic clays, carbonate cements and dissolution. The early to intermediate stage of diagenetic realm was estimated in the studied samples based on diagenetic events, e.g., mechanical compaction, chloritization, carbonate precipitation, dissolution, quartz overgrowth and authigenesis of clays. The reservoir quality was not much affected by the effects of diagenesis. However it was controlled mostly by the mechanical compaction including its grain size, sorting and fabric. In addition the authigenic cements (quartz, clays and carbonate) slightly modified its porosity and permeability status during diagenesis. The measured average thin section porosity and its permeability suggested good to excellent reservoir quality for hydrocarbon accumulation and production. Suggested Reviewers: Md. Sultanul Islam, PhD Professor, University of Rajshahi, Bangladesh [email protected] A good expert. Badrul Imam, PhD Professor, University of Dhaka, Bangladesh [email protected] Pioneer sedimentary geologist. M. P. Singh, PhD Professor, Banaras Hindu University [email protected] 244 Powered by Editorial Manager® and Preprint Manager® from Aries Systems Corporation Journal of the Geological Society of India

LOG BASED PETROPHYSICAL ANALYSIS OF MIO-PLIOCENE SANDSTONE RESERVOIR ENCOUNTERED IN WELL RASHIDPUR 4, BENGAL BASIN, BANGLADESH --Manuscript Draft--

Manuscript Number: Full Title: LOG BASED PETROPHYSICAL ANALYSIS OF MIO-PLIOCENE SANDSTONE RESERVOIR ENCOUNTERED IN WELL RASHIDPUR 4, BENGAL BASIN, BANGLADESH Article Type: Research Article Corresponding Author: Md. Farhaduzzaman, PhD University of Malaya Kuala Lumpur, Selangor MALAYSIA Corresponding Author Secondary Information: Corresponding Author's Institution: University of Malaya Corresponding Author's Secondary Institution: First Author: Md. Aminul Islam, PhD First Author Secondary Information: Order of Authors: Md. Aminul Islam, PhD Md. Farhaduzzaman, PhD Wan Hasiah Abdullah, PhD Joyanta Dutta, MSc Order of Authors Secondary Information: Abstract: Rashidpur is located in the northeastern part of Bangladesh. It is surrounded three sides by India and one small part by Myanmar. Gamma-ray, spontaneous potential, density, neutron, resistivity, caliper, temperature and sonic logs are used to analyze petrophysical parameters of the well Rashidpur 4, Bangladesh. Quantitative measurements of different factors such as shale volume, porosity, permeability, water saturation, hydrocarbon saturation and bulk volume of water are carried out using well logs. Petrographic and XRD results based on several core samples are also compared with log-derived parameters. Twenty permeable zones are identified whereby four are hydrocarbon bearing in the studied Mio-Pliocene reservoir sandstones. Measured shale volume ranges from 11% to 38% and porosity is 19% - 28%. However, log- derived porosity is slightly higher than the thin section porosity. Water saturation of the interested zones varies from 14-38%, 13-39% and 16-41% measured from Schlumberger, Fertl and Simandoux formula respectively. Conversely, hydrocarbon saturation of the examined hydrocarbon zones ranges from 62-86%, 61-83% and 59- 84% respectively. In the analyzed zones, the permeability values are calculated as 28- 305 mD. Good to very good quality hydrocarbon reservoir is appraised for the studied four zones based on the petrophysical parameters, petrographic observation and XRD analysis. Nonetheless, Zone 4 is the best quality reservoir for hydrocarbon. Suggested Reviewers: Delwar Hossain, PhD Professor, Jahangirnagar University, Dhaka [email protected] He is an experienced Petrophysicist based on Bengal Basin. M. P. Singh, PhD Professor, Banaras Hindu University, India [email protected] Prof. Singh is an excellent academician who have a vast research experience.

245 Powered by Editorial Manager® and ProduXion Manager® from Aries Systems Corporation 6/10/13 Gmail - [Sains Malaysiana] Submission Acknowledgement

Farhaduzzaman Farhad

[Sains Malaysiana] Submission Acknowledgement 1 message

R. Abd-Shukor Mon, Jun 10, 2013 at 3:28 PM To: Mr Md Farhaduzzaman

Mr Md Farhaduzzaman:

Thank you for submitting the manuscript, "Petroleum Source Rock Properties of the Neogene Bhuban Shales, Bengal Basin, Bangladesh" to Sains Malaysiana. With the online journal management system that we are using, you will be able to track its progress through the editorial process by logging in to the journal web site:

Manuscript URL: http://ejournal.ukm.my/jsm/author/submission/3274 Username: farhad

If you have any questions, please contact me. Thank you for considering this journal as a venue for your work.

R. Abd-Shukor Sains Malaysiana ______Sains Malaysiana http://202.185.40.102/ojs/index.php/jsm

246 https://mail.google.com/mail/u/0/?ui=2&ik=a9898f86d6&view=pt&search=inbox&th=13f2cfc6fa0097d7 1/1 6/21/13 Gmail - Acknowledgement (Malaysian Journal of Science)

Farhaduzzaman Farhad

Acknowledgement (Malaysian Journal of Science) 1 message

Editorial Assistant, Malaysian Journal of Science Fri, Jun 21, 2013 at 4:59 PM Reply-To: "Editorial Assistant, Malaysian Journal of Science" To: Farhaduzzaman Cc: "[email protected]" , "DR.P.Agamuthu"

Dear Dr Wan Hasiah, MALAYSIAN JOURNAL OF SCIENCE

This is to acknowledge receipt of your team’s manuscript, entitled:

" ORGANIC GEOCHEMICAL AND PETROLOGICAL EVALUATION OF THE EARLY PLIOCENE BOKA BIL SHALES OF THE BENGAL BASIN, BANGLADESH "

The manuscript has been filed with the manuscript number 025/2013/B.

Please use this reference numbers in all future correspondence with the Secretariat.

the decision of requesting the services of the experts provided is at the sole discretion of the Editor-in-Chief or Associate Editor.

Thank you for considering the Malaysian Journal of Science.

Yours Sincerely,

Professor Dr. P. Agamuthu Editor – In – Chief Malaysian Journal of Science Faculty of Science University of Malaya 50603 Kuala Lumpur 247 https://mail.google.com/mail/u/0/?ui=2&ik=a9898f86d6&view=pt&search=inbox&th=13f65f5e08d50abb 1/3 Appendix B1: Some definitions and measurement terms used in the literature.

248 Appendix B2: Peak assignments for alkane HCs in the gas chromatograms of the aliphatic fractions (i) in the m/z 191 mass fragmentogram and (ii) m/z 217 mass fragmentogram.

249 Appendix B3: Some important standard parameters used for petroleum source rock screening in the thesis.

250 Appendix C1: TOC (wt.%) of both Boka Bil and Bhuban shales plotted with vertical depth profile (m) of the study area. It shows that the TOC increases with overall depth increasing irrespective of any particular wells.

251 Appendix C2: Modified van Krevelen diagram (HI versus OI) shows that the analyzed both Bhuban and Boka Bil samples consist of a mixture of Type III and II kerogens (see Appendices B1 and B3 for definitions).

252 Appendix C3: PyGC pyrograms of Boka Bil and Bhuban shales (PT5SH14 and KM1SH4) display a mixed kerogen of Types III and II.

253 Appendix C4: Pictorial presentation of CPI values shows that the members of odd- numbered and even-numbered n-alkanes alternately predominate each other in both of the analyzed Bhuban and Boka Bil samples.

254 Appendix C5: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Boka Bil sample (PT5SH10). It represents immature oil window (peak i.d. in Appendix B).

255 Appendix C6: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Boka Bil sample (BK9SH71). It represents mature oil window (peak i.d. in Appendix B).

256 Appendix C7: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Bhuban sample (FN2SH7). It represents immature oil window (peak i.d. in Appendix B).

257 Appendix C8: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Bhuban sample (BG1SH6). It represents mature oil window (peak i.d. in Appendix B).

258 Appendix C9: Cross-plot of bc/C30-hopane and ol/C30-hopane (oleanane index) with respective depth (samples) shows that bc/C30-hopane ratio decreases and ol/C30-hopane ratio increases with depth. It indicates the relative maturity increase with depth.

259 Appendix C10: The identified similar organic geochemical and organic petrological properties of the analyzed Bhuban and Boka Bil Formations, Bengal Basin, Bangladesh.

260 Appendix D1: Bar diagram displaying the concentrations of macerals and minerals (vol. %) of the studied Permian coals of Bangladesh.

261 Appendix D2: Bar diagram displaying the concentrations of microlithotypes (maceral associations) and carbominerites (vol. %) of the studied Permian coals of Bangladesh.

262 Appendix E1: Comparison between SRA and RE results of the analyzed coal, carbargillite and mudstone samples (refer to Appendix B1).

263 Appendix E2: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied coal sample (DPCL35) of Dighipara Coal Basin (peak i.d. in

Appendix B2).

264 Appendix E3: Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied carbargillite sample (BPCR11) of Barapukuria Coal Basin (peak i.d. in Appendix B2).

265 Appendix E4: Pictorial presentation of CPI values whereby all of the analyzed coal, carbargillite and mudstone samples show the dominance of odd carbon numbered n- alkanes. It indicates the terrestrial dominated organic facies in the depositional system.

266

Appendix F1: A sample report of a reference management software EndNote X5 that has been used for the thesis.

267

Appendix F2: A standard report of StyleWriter 4 software for checking English Language. It shows the status of English used in the thesis is “Excellent”.

268

Appendix F3: A sample report for checking the originality using Turnitin software. It reports 19% similarity index with the thesis whereas more than 5% comes from the publication of author himself based on present research.

269 Appendix G: Contributors of the thesis.

I received BSc (Honors) and MSc in Geology in the year 2001 and 2002 respectively from Jahangirnagar University, Dhaka, Bangladesh. I have 5 years working experience with Asia Energy Corporation Pty Ltd (UK base company) as an Assistant Geologist (Exploration) from August 2004 to June 2009. After leaving Asia Energy, I have been working with Sylhet Gas Fields Limited, a company of Petrobangla as an Assistant Manager (Development Geology) since July 2009. I’ve prepared this thesis partly based on the petroleum systems of Bengal Basin, Bangladesh as part of my PhD research at the Department of Geology, UM. Some of my research papers have already been published in different national and international high impact journals. I am a member of AAPG, SEG, GSM, BGS and SEAPEX. Author: Md. Farhaduzzaman Prof. Wan received her BSc (Honors) in Geology from University of Malaya, Malaysia. She accomplished her MSc and PhD in Petroleum Systems of North Sea from the New Castle Upon Tyne University, UK. After PhD, she joined as a faculty member at Geology Department, UM in 1989 and now continuing here as a Professor of Petroleum Geoscience and Coal. She has already published around one hundreds research articles in national and international high impact journals. More than 10 PhD students already graduated under her supervision and 15 more PhD students are continuing their researches. The areas of her expertise include Petroleum Geology (Petroleum Systems), Petroleum Geochemistry and

Supervisor: Coal Petrology. She is a member of AAPG, TSOP, ICCP, Prof. Wan Hasiah Binti Abdullah GSM, IGM, SEAPEX and SPE. Currently she is the coordinator of the MSc Petroleum Geology Program at UM. After BSc (Honors) and MSc in Geology and Mining from Rajshahi University, Bangladesh, Dr. Aminul joined as a Geologist in Petrobangla, the state-owned oil/gas organization. He joined as a faculty member in Geology and Mining Department, RU in 2001 after 8 years’ service with Petrobangla. Based on Petroleum Geoscience and Geophysics, he did his MSc from NUST, Norway and PhD from Tsukuba University, Japan. He was a faculty member of Geology Department, UM and after that he joined in the Petroleum Geoscience Department, UBD, Brunei in 2011. He has already published around sixty research articles in national and international high impact journals. The areas of his expertise include Petroleum Geology and Geophysics. He is a member Co-supervisor: of AAPG, GSM, BGS, SEAPEX and SPE. Dr. Md. Aminul Islam

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